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 Wednesday, January 20, 1999 commencing at 9:00 a.m. --------------------- TECHNICAL CONFERENCE "Distribution Assets and Capital Plans; issues relevant to Distribution OM&A/Revenue Requirements." VOLUME 7 --------------------- F A C I L I T A T O R : DAVID HARDY Board Technical Staff 799 A P P E A R A N C E S DAVID HARDY ) Board Technical Staff KATHI LITT ) in conjunction with: ANN BULKLEY ) Reed Consulting WILLIAM HOPKINS ) VIPIN SURI ) Ontario Hydro JOHN ROGERS ) Services Company Inc. DOUG URBAN ) [SERVCO] SUSAN FRANK ) MYLES D'ARCEY ) MICHAEL GILLESPIE ) MARCEL REGHELINI ) 800 ---Upon commencing at 9:00 a.m. MR. HARDY: Good morning. Why don't we begin? Actually we will probably begin on time. It's always pleasurable to me. My name is Dave Hardy and I've been asked by the Ontario Energy Board to facilitate the Technical Conferences. This is a continuation of a series of rate order Technical Conferences that's been ongoing for several days now. My role is mainly to have an eye for process and fairness and also keep the agenda on track and try to keep it as informal as possible. I am going to go through my full introduction this morning. For those of you who have heard it before, please bear with me, but I do see some new faces, new participants and I just want to make clear how we're going to be proceeding today. As I mentioned, there have been a series of Technical Conferences already focusing on mainly transmission rates. Today and tomorrow we're going to be discussing distribution assets and capital plans and also issues relevant to distribution OM&A and revenue requirements. In the past, there was a memo that was distributed by the Board on December 18th that highlighted some of the issues that are relevant to the Board and we've been addressing those issues. If you don't have a copy of that memo, it can be obtained from Board Staff. There have been supplemental filings to date for Overview 801 (Facilitator) the transmission application. Ontario Hydro or SERVCO staff can inform you about the additional supplemental filings. There also have been some additional information provided by participants as well. We are also keeping a list of information that is going to be brought forward or questions that could not have been answered at the time by SERVCO and will be brought forward and some of that information has been coming forward at these Technical Conferences. Before we proceed with the first panel, I'd just like to go through some of the procedures I'm following. Generally we've found it useful to start with SERVCO presentations, then to move on to Board Staff and Consultant questions of those presentations and then opening up the floor to participants. Again, try and keep it as informal as possible, so once we do open up the floor to participants, we may be moving backwards and forwards in terms of Board Consultants and Staff and participants, and that's fine with me. This is an opportunity for SERVCO to explain the application and the filing. It's also an opportunity for us, participants and Board Staff, to test the information that's been brought forward. To that end, certainly I'll try to make sure that you have an opportunity to fully ask any questions you have of SERVCO and for SERVCO to fully explain their responses. Again, there may be some instances for one reason or another that SERVCO cannot provide a response at the Overview 802 (Facilitator) current time. We'll note that and expect that to come forward as appropriate. There is a transcript available and will be available. It can be purchased from Farr and Associates. There are some transcripts available from Board Staff as well. Because we are transcribing the sessions, it's important as you come forward to ask questions to grab a mike. We do have people at the mikes now, but throughout the morning, they'll be, after asking those questions, taking a seat further back and every mike is opened up, so it's a bit of an awkward part of this particular setup but we do have to speak into the mikes. When you do speak into the mike, please state your name so that the reporters can note that. And finally, there is a registration list and it is important that you do sign the registration list, particularly if your attendance here is an aspect of support. Okay. That ends my opening introductory comments. At this point, I'd like to turn to the SERVCO staff and have the panel introduce yourselves and then the floor is yours to present the information on the application. MR. SURI: Thank you, Dave. My name is Vipin Suri. I'm the General Manager for Distribution Network Asset Management. MR. ROGERS: John Rogers, Director of Asset Presentation 803 (V. Suri - SERVCO) Sustainment. MR. URBAN: Doug Urban, Director of Network Planning and Development. MS. FRANK: Susan Frank, Wires Integration OHSC. MR. D'ARCEY: And Myles Darcey, Engineering Services. MR. SURI: Thank you, panel members. PRESENTATION BY MR. SURI: What we're going to do is start with a presentation about distribution and OM&A capital programs. Myself and panel members are happy to be here and the purpose here is to explain the application which is in front of the Board and really answer any questions all of you have. The main purpose of the presentation is to seek approval for the revenue requirements for the distribution and remote communities. The names of the panel members are on the overhead. The panel members have just introduced themselves. And the panel today, what we will be discussing is mainly the capital programs. There's a name on the slide which is Graham Henderson. He will be added to the panel. He will replace Doug Urban tomorrow and he will be dealing with monopoly supply items. At this point in time I'd like to give you an outline of the presentation, what we're going to be going through. I will take about 45 minutes to an hour to explain what the distribution programs are, what the Presentation 804 (V. Suri - SERVCO) distribution business is, the assets. The slide indicates the outline of the presentation. As I indicated, we're going to cover in general what the distribution business is all about. We will cover distribution system, a description of the system, the asset categories in the distribution system and give you a cost overview of distribution capital programs and also talk about age and condition of the assets and with some performance and service standards which are being developed for the distribution business. This chart was shown to you by Rod Taylor on the opening day of this conference which deals with the organization of Ontario Hydro Services Company. On the chart, it shows different parts of Ontario Hydro Services Company. The part which I belong to is the DNAM part which is the distribution network asset management. You have heard from Dave Barrie and the Transmission panel before and now we're talking about the distribution side of it. Also included in the application are the costs of customer care services which appears under Gerry O'Hearn, the retail energy services. And those are the two items which we will be discussing at this point in time as part of the distribution. At this time I would like to talk about what the structure of DNAM is. There were some questions about the structure of distribution network asset management, what functions we have and what we have done is taken an Presentation 805 (V. Suri - SERVCO) organizational chart and taken it below that level of the OHSC organization. Essentially the organization of distribution network asset management follows how the programs have been structured in capital and OM&A. The main categories of the programs are dealing with operations management. We have a director for that, Mark Burman; Director of Network Planning and Development, which is Doug Urban and Doug is on the panel today; a Director of Asset Sustainment, John Rogers, and John is also on the panel today. Then we have a group of people under direction of our Director of Contracting and Network Support which is Mark Khanna. And essentially, there's a total of 105 people in the distribution network group and this group was set up as we implemented the asset management model within the distribution business in the Services Company. The functions of these people we will be describing through the programs. All the programs which you will hear today in capital and for OM&A tomorrow are broken into the three categories: sustaining capital, development capital and operations capital. Let's look at what the business distribution system is responsible for. You are familiar with this chart. It is in the rate order application. And the primary function is the transportation of power from the bulk supply points to the customers. Mainly we are dealing with the assets which are less than 50,000 volts, 50 kV, and certainly the system is comprised of low- Presentation 806 (V. Suri - SERVCO) voltage feeders, distribution stations and rural feeders. From the distribution system we serve 202 of the 276 municipal electric utilities. Also served from this system directly are 45 direct industrial customers. In addition to that, we have 960,000 of retail customers which are served from the distribution system. Essentially it's a radial system and the difference between the transmission and distribution really is the transmission is an integrated bulk delivery system where distribution is radial delivery to the customers. And the service boundaries for the distribution system are the provincial boundaries, those areas which are not served by municipal electric utilities, also those areas which do not fall under the remote communities. With the exception of the customers served by municipal electric utilities or through remote communities, the distribution system serves all of the retail customers in the Province of Ontario. I want to give you some background about how the distribution system was managed in the past. We have gone through a number of organizational changes in the past and just from a history point of view starting in 1993, how the distribution system was organized and where are we today and what kind of changes and initiatives distribution is taking. The distribution system within Ontario Hydro was managed through 15 utilities. We had a reorganization of Presentation 807 (V. Suri - SERVCO) the whole corporation which took place back in 1993. At that point in time the retail distribution system was organized into 15 different electric utilities. Those utilities essentially were similarly set up as the municipal electric utility were, that they will have their geographic boundaries and the managers within those boundaries will be responsible for management of the assets and also be responsible for management of the work. So the execution of work and the decision-making regarding the assets were all done in those geographically managed retail utilities. Subsequently, those 15 utilities were amalgamated into eight utilities and from eight utilities starting in I think latter part of 1997, which is probably the end of November 1997 when we adopted the asset management model in the distribution system, at that point in time we had created the distribution network asset management group and the network services group. The concept here was that when the utilities were performing or managing their assets and the work within their geographic boundaries, they set up their own priorities within each utility. Their budgets were set. The individual utilities would set up their own programs. In many cases some of the utility managers would also have their own design standards and start developing their own activities. The concept was that when we introduced the asset management model that we will start looking at the Presentation 808 (V. Suri - SERVCO) priorities of the work programs on a provincial basis. The records, the information which was available in the field at that point in time was also contained in the local offices. Each office will have their information on the maps and the maps, they will draw up the feeders and the feeders on the map will show what customers are being served from those feeders. Essentially the data was contained in manual records and manual maps and the process of moving into an asset management model is also looking at this whole data and information on a priority basis, a provincial priority basis so we can look at these programs in that manner. A number of initiatives which are currently going on in the distribution system are shown in the following slide. As I mentioned, we started the implementation of the asset management model back in 1997 in the distribution system. And at this particular time we are proceeding towards the full implementation of the asset management model. Along with that, we have been redesigning all the business processes within the distribution system and also the process for implementation of these redesigned processes has just begun now. You've heard from Myles D'Arcey in the Transmission panel, and Myles is here also to talk about the execution of work, because one of the elements of the asset management model is that the decision-making around Presentation 809 (V. Suri - SERVCO) the assets is with the asset manager group and certainly execution of work is with the network services group. The concept here is to look in the labour productivity issues and so on. Customer responsiveness is another area certainly we are looking at and also focus is being placed on looking at the condition of the assets. The key point here that we need to know the information about the assets: where these assets are, what condition they are in, who is being fed from these assets, what customers are connected and also what state the system is this in, what live information we can obtain about the systems. So the programs you are about to hear really are going to be focusing on these areas dealing with the implementation of the business processes which will lead to reduced costs and also dealing with the other programs. Before we get into the programs, I want to give you a picture of what the asset base of these distribution assets are. I think we show the asset categories in two ways. The first category which breaks the asset between line station and miscellaneous. The details are available in the rate order application binder. I provided another cut to those numbers to put it in perspective that how the programs are developed and what asset categories we are really looking into. As you will note from the slide, the total asset Presentation 810 (V. Suri - SERVCO) base is $2.5-billion. Out of the $2.5-billion of the assets, 29 per cent of the assets are in poles category; 27 per cent of the assets are in conductors category; and 16 per cent are in the transformers category. So you will note that up to 72 per cent of all distribution assets are really tied into poles, conductors and transformers. Essentially if that's the assets which are being managed, and the asset manager being responsible for the performance of these assets, the majority of our programs are going to be looking at the condition of these assets, sustaining these assets, maintaining them in proper condition. A number of assets which we have here in terms of numbers, certainly you are looking at one-and-a-half- million poles in the distribution system. We are not a utility which counts customer per pole, we count poles per customer. The reason for that is that we have 960,000 customers and we have 1.5-million poles. So we have more poles in the system than we have customers. The system, as I indicated, is a rural system, it is a radial system. It stretches all over the Province of Ontario. It's mainly over a system supported by poles and certainly it is subjected to all the adverse conditions of weather and everything else which goes along with it. In terms of conductors, we have 119,000 kilometres of conductor in the Province of Ontario which is managed to the distribution system. We have 449,000 transformers and over 1-million meters and that's the kind Presentation 811 (V. Suri - SERVCO) of an asset base which is being looked at. Before developing the programs we started looking at what kind of strategies we should be following. The following strategies are going to be indicated by the direction which we have used in developing the capital programs and OM&A programs for distribution. The strategies which were developed were basically broken into three categories; the strategies which enhance customer value, strategies for enhancing shareholder value and also carrying out the stewardship role of the Services Company in the area of environment, public and worker safety. Dealing with the customer value, the programs have been developed to maintain the system reliability levels and power quality and service levels which we have today in the system. Strategies have been developed to reduce the costs because we are implementing the redesigned business processes which the implementation process, as I just indicated, has just begun. Also making sure that we are ensuring sustained system capabilities. The concept of managing outages proactively. What we have in the system is, at this point in time, that the customer is the one who notifies us saying the customer is without power. The knowledge base about the distribution system is such that we do not have the distribution system automated. We do not have any automated outage management Presentation 812 (V. Suri - SERVCO) systems or geographical information systems like a GIS system that will tell us or give us real-time information about the distribution system. So the concept is that we are trying to develop programs and systems so we can manage the outages in a proactive manner. The concept from a shareholder point of view is improving or maximizing the capital efficiency which is really saying maximizing the lifecycle cost of distribution assets and also increasing the utilization of distribution assets. Certainly one of the categories we have on the distribution side is the line losses. The size of conductor we use on the distribution facilities and type of voltages used certainly leads to a lot of line losses on the distribution system and us trying to manage that will definitely add more value to the whole system. A number of issues that we will cover in some programs which are environment related, we have contaminated lands at distribution sites, distribution station sites. We have 940 distribution stations in the province and certainly the land around the distribution stations can be contaminated. It could be contaminated as a result of some spills from the oil from the transformers, it could be contaminated from leaching of chemicals from the poles which are at the transmission site, or it could be contaminated by spraying of chemicals to control vegetation at the distribution sites. Presentation 813 (V. Suri - SERVCO) So we are looking at essentially what those contaminated land sites are and we can remediate them. Also, PCBs are in the system. Transformers, oils use PCBs and certainly the programs talk about eliminating those PCBs. Lately we've had a number of public contact with our facilities and we are dealing with education programs to educate the public about to make sure that the public safety issues are addressed. So these are the strategies which have been looked at and have been used to develop the programs. What I would like to do is talk about the capital programs at this stage. As I indicated earlier, we will talk about the OM&A programs tomorrow. The package which we have handed out to you today includes all of the slides which we're going to use today and tomorrow, but we will finish -- there's a slide which deals with the conclusions of the capital program. Let's look at the total capital program and in all the slides we have tried to provide numbers for 1998, 1999 and 2000. And certainly -- some of the details have already been included as part of the rate order application and then further questions can be taken by the panel members and myself. The distribution capital program in total is 203-million for 1999 and the number for the Year 2000 is 154, 155, in that range. All capital programs, as I indicated before, are Presentation 814 (V. Suri - SERVCO) broken into the main three categories just the way the transmission programs are broken into sustaining capital, development capital and operations capital. On the distribution side, we also have customer care capital and distribution support capital. So there are basically five categories. Transmission, when you looked at it, there were four categories. There's a fifth category of customer care on the distribution side. The next slide will show you the breakdown between these different categories, essentially sustainment, development, operations, customer care, distribution support and indicating the changes in costs from 1998, 1999 and the Year 2000. And the reasons for changes in these costs, we will be addressing that in a little bit more detail. The concept here is that the distribution capital which is being proposed in the forecast is really to look after the assets. Just to give you an idea, that we will be replacing a number of poles through many, many programs on the distribution side. If we an add up all the programs which are proposed, it will talk about that we will approximately replace 23,000 poles next year, in the Year 1999, which is, if you take the total pole count of 1-1/2-million, it's less than 1-1/2 per cent of our poles that would be replaced next year. We will be replacing approximately 1,150 kilometres of conductor. And what I've done here is, these numbers are basically adding up all the programs Presentation 815 (V. Suri - SERVCO) because we have pole replacement programs, we have conductor replacement programs, but when we relocate our lines because the Ministry of Transportation of Ontario have decided or a municipality has decided to widen some roads and relocate, at that point in time some poles are also replaced. So pole replacements, conductor replacements come in through many, many programs. Similarly, we will be replacing over 2,700 transformers in 1999. In addition to that, a lot of the capital work which is in the development area also is a demand kind of capital work, demands which are placed on us by customers. The forecast includes a planned connection of 16,000 customers, new customers next year on the system. To connect the new customers, we have to build new facilities and that's all part of that. Similarly, there may be 11,000 customers who we have forecasted will be requiring upgrades to the service they have. And in order to look at basically increasing load, we have planned for construction of two new DSs and associated line facilities which are part of the capital programs. Let's look at individual categories, each one of these categories, sustaining capital, development capital and so on, and try to just get into a little bit more -- drill down a little bit further and see what other programs are in there. The slide shows the breakdown of sustaining capital on the distribution system and sustaining capital Presentation 816 (V. Suri - SERVCO) essentially is -- we had a number of 83-million for 1998 and 68-million for 1999 and 78-million for 2000, and essentially the slide breaks it down into different categories. In 1998 numbers, you will see a category called 'ice storm' which was the January ice storm, the storm of the century. The capital costs for that storm which were included in sustaining capital in 1998 were $50-million, so that was an extraordinary item. But the program items which are included in there, if you look at them, are really dealing with lines and stations capital, which would be looking at the transformers, looking at the feeders, looking at the conductors, the conductors which may be essentially causing some public safety issues or deteriorating, specific conductors. We are looking at in that program, is No. 4 ACSR, and No. 6 copper conductors which are going to be replaced. It also looks at the stations which is the fencing around the stations or groundings. It also looks at some poles. We have some seven yellow pine poles on our system which have posed worker safety hazards for us. We have some poles which are treated with pentachlorophenol, which is PCP poles, and the program talks about replacement of all these poles in sensitive locations, as penta can be leached into the ground and if grounds are close to the water and essentially those chemicals can enter the water streams. The dollars also make an allowance for some kind of storm damage essentially and this is under facilities Presentation 817 (V. Suri - SERVCO) and lines and stations line. Sustaining capital also looks at specific asset condition restorations. When we started the asset management model, one of the things the asset managers got involved in back in 1977 was really started an effort on looking at the condition of the assets. And the condition of the assets basically were looked at and that process is continuing at this point in time. As I indicated, the information about the distribution system assets is very limited. But based on the information we have available, we have developed some programs to look at the condition of the assets, and this forecast of capital programs includes allowances for replacement of some poles, some conductors and replacement of some submarine cable which directly was a result of the asset condition assessments which we have conducted. Sustaining capital also has a breakdown for relocation capitals or joint-use capitals. We have joint-use programs with other utilities like the telephone utilities and part of those joint-use agreements would be that we may have to replace some poles. The relocation programs, as I indicated, will deal with relocations of lines because the roads are being widened or anything else. And essentially, that's what the breakdown in this program is, which deals with specifically the sustainment portion of the capital. We're going to look at the other capital categories which is the development capital and the Presentation 818 (V. Suri - SERVCO) capital dealing with operations in the next slide. Okay. The development capital, one of the first categories in that capital is the customer connections, upgrades, purchase of meters. As I indicated, the new customers come on the system, existing customers request upgrades to their service and essentially the program talks about the $37-million in 1998, $37- in 1999 and $35- in the Year 2000, which basically makes an assumption that on average, we need to connect about 16,000 customers per year and that's the average number which has been used for these numbers. System capability and reinforcement programs deal with providing the capacity on the system which may be required as a result of the load growth and certainly building new DSs and other feeders to go with it. In the operations side, this is the first time we have some programs included in this category and this is really a program which is DOMCAMS - the acronyms are explained later on in the presentation and in the rate order application - which really stands for distribution operations management centre and asset management system. I have a slide on DOMCAMS later on to talk about it in a little more detail, but what this is, this is an integrated GIS and outage management system which really talks about, that on a spacial data base, where your assets are located, and also talks about, saying who is being fed from those assets. That information is contained in the system. It starts with the conversion of Presentation 819 (V. Suri - SERVCO) the existing assets which we have or existing information, like maps which we have in the system, and also have a link to the work management system. So as you install or remove facilities from our system, that these assets or these records can be updated. It is also an asset registry for us which will tell us exactly what the assets are and then we can put in the other attributes, the age of these assets, when these assets were installed, then we can also put in there the condition of the assets which will help us in developing the programs which are the replacement programs or maintenance programs and find an appropriate tradeoff between these programs. The SCADA part in the system also deals with the distribution category, is the system control and data acquisition part of it. This is really putting some metering points in the system at the DS sites, putting some remote terminal units so we can start getting some live information about the distribution system. The distribution as such is not monitored. We already have a very limited monitoring on the low-voltage lines, but there's no monitoring on the rural side of the facilities. So the plan here would be to combine that at a distribution operations management centre, bring all this information, the real-time information about the system, and also information about the assets which we have, the conditions and work programs which are going on in that particular category. Presentation 820 (V. Suri - SERVCO) In the customer care capital, what we have done is, the chart basically combines the two together, the customer care and distribution support capital. And the customer care capital deals with the metering cost of the customer service system. It also deals with the call centre and it has some dollars for office and administration in there. The distribution support deals with many of the infrastructure implementation costs and the performance enhancement project, which is called PEP, and also deals with the pay and human resources projects and so on. At this point in time, I would like to take a few minutes to talk about how we've gone about looking at the age of the assets - what is the age of the assets we have today and what kind of condition these assets are and then what kind of programs really get developed out of this analysis. As I mentioned before, the main categories for us to look at are poles, conductor, transformer. We're looking at poles on the low-voltage side, which is the LV system as we call it, and then we're looking at the poles on the rural side. We're looking at conductor on both systems. In the rate order application, you have age profile of service transformers, which is the station transformers, and we'll also talk about -- sorry, in the application, you have station transformers and we're going to talk about service transformers now which are the overhead transformers. Presentation 821 (V. Suri - SERVCO) The low-voltage conductor age profile, it indicates essentially that the normal expectancy of these poles is 55 years. And -- sorry, where am I? Okay. Sorry, I'm on the conductor slide. The low-voltage conductor age profile that we are -- the age is 55 years and there are a number of conductors, if you look at the first bar, which talks about 1548 kilometres of conductor has reached the expected age. Conductor has, as probably you are aware of it, has steel cores which deteriorate and which results in fracture under windy conditions and so on and results in outages. If you look at the poles, the expected life of low-voltage poles is 35 years. The total number of poles, LV poles on the system is 231,000 plus. And the number of poles which are in excess of 35 years today is 104,000. So a large quantity of poles have reached their expected age and the point here in looking at the age of these assets is that is a starting point for us. We look at what the age of these assets is, then we start looking at those poles and those conductors and those transformers who have reached their expected age and then start examining the condition of the assets. Programs definitely just do not look at just replacing all the poles which have reached, or conductors which have reached their expected age. It really is starting point for us that we look at the age of these assets and then start looking at the condition of them. Presentation 822 (V. Suri - SERVCO) Similarly, on the rural conductor age profile, the conductor has the same expected life of 55 years, like LV conductor. We have 8,000 kilometres of rural conductor which have reached or exceeded the expected life. On the rural poles, the same expected life. These are all wood poles on the system, the majority of them are. We do use some steel poles and we are examining the introduction of the steel poles on a much wider basis on the system. The expected life of wood poles being 35 years, we have 423,000 poles out of a total of 1.4-million approximately have reached their expected life. Put that in context with how many poles have reached their expected life and when we start looking at the condition of these poles, the total program talks about replacement of total of 23,000 poles in 1999. Service transformers, over 63,000 service transformers have reached their expected life of 35 years. As I indicated earlier, the total number for these service transformers, which the majority of them are pole top transformers, is 449,000 on the system. The next couple of slides really try to give you an indication of how the poles have been deteriorating and there are some pictures there. The poles have decay and it could be an internal core decay and it could be an external decay. That's why these wood poles are treated with chemicals to extend their life. And we have been examining certain poles and Presentation 823 (V. Suri - SERVCO) looking at -- we start with saying which are the poles which have exceeded their expected life, look at their condition, and if you find poles in these conditions certainly they really need to be replaced. Many of the poles, and I would say at least -- I would say about a little bit less than half of our poles are not on road allowances, they are off-road. And off- road means they have to be climbed. When you have to climb the poles, the power line maintainers obviously -- we are concerned about their safety and we want to make sure that, you know, we are not reaching a situation that they are climbing unsafe poles. A picture of a pole which was put in in 1948 is in the next slide. I think the picture is in your handout, which really indicates that maybe perhaps back in those days we did use poles like that and certainly these poles are structurally weak and totally unsafe to climb. These kind of poles definitely need to be replaced. Looking at the age of the assets and looking at the condition of these assets, what we do is then we try developing some programs and the programs perhaps dealing with the condition of the assets. And let's look at the three categories of the programs which we have included in addition to the programs which normally we carry out. These are some of the things which we started looking at, the asset conditions on a provincial basis, started setting up priorities on a provincial basis that Presentation 824 (V. Suri - SERVCO) look at the condition of the assets, look at the lack of information which we have or lack of adequate information which we have or fragmented information which we have, and also look at the environmental concerns. The programs, some of them already talked about, are detailed in the next slide. In this slide we attempted to summarize all programs which have resulted as a result of asset condition assessments. Many of them are OM&A programs which we will be discussing them tomorrow. The three main capital programs are the pole replacement program, the conductor replacement program and the submarine cable program. These programs, as I indicated, are essentially looking at the age of these assets, looking at the condition of these assets and saying how many poles we need to be replacing in the system because their condition has deterioriated to a point that either they are resulting in more outages because they are having failures of components or they are posing safety hazards to workers, to public, to other contractors and other people who work on our system. The concept here would be to develop these programs and essentially correct the situations which are causing sort of immature failures and other unsafe conditions. I want to talk about the other category of programs which also deal with the information about the Presentation 825 (V. Suri - SERVCO) assets. We have looked at the age of the assets, condition of the assets, information about the assets themselves. This is where we talked about two programs, the development capital programs; the DOMCAMS: distribution operation management centre and assset management system; and SCADA, which is system control and data acquisition. The current capability, as I indicated how we were managing the distribution system in the past through eight utilities or 15 utilities prior to that, is fragmented. We have maps available in the field and the maps have manual drawings made on them, the drafting people are creating those maps. Now, if you are looking at the system on a provincial basis at one place, all those maps need to be put in an automated system someplace, in a GIS kind of a system, so we can manage the outages in a much more proactive manner. We would like to be in a position I think with this kind of an approach that certainly the outages could be managed in a much more efficient and much more effective manner so when the customers phone, that we have the intelligence available of which distribution station is out of service, we can inform the customers in a much more appropriate manner, we can dispatch the crews in a much more efficient manner and looking at the whole thing on a provincial basis. And the dollars in these programs are also shown on the next slide. There is an OM&A portion in these Presentation 826 (V. Suri - SERVCO) programs which can be discussed tomorrow, but the capital programs include the capital of $45-million in 1999 and $19-million in capital. Some of these programs have been initiated. They have started in 1998 and some will be completed in 1999. The others, like the SCADA one, will be completed in the Year 2001. In a conceptual manner, I have a diagram for the DOMCAMS and the SCADA, which is really an attempt to automate the operations management work flows for distribution. As I indicated, the lack of information, lack of adequate information on the distribution system, lack of automation on the distribution system is resulting in a need that we need to be able to have a centre, a control centre someplace in this province where we can look at the whole distribution system. It will have an interface with the customer service system which we have today, it will allow us a dispatch of the crews right from the operation centre, it will bring in and give information from a work management perspective dealing with network services that we can dispatch the work to them and then they can give a feedback to us, essentially that what work has been completed and what new facilities have been put in place. Also it would help us in designing the system better because you will have all the information necessary to manage the distribution system. Presentation 827 (V. Suri - SERVCO) Ultimately, all this is going to be leading into labour productivity improvements, it will be leading up to improving the performance of the assets in total. I have got a slide showing just the environmental programs, all of them shown on the next slide. Like in the other slides, we have some OM&A components in these programs. So that we put these programs in perspective, we put the OM&A and capital on the same slide, but the capital portion of the environmental programs deals with essentially two components which is replacement of some PCB contaminated transformers and also replacement of penta-treated poles, pentachlorophenol-treated poles. The total dollars for 1999 is $4.1-million and the dollars for 2000 is 5-million. I want to switch over to the measure side. We've covered essentially the assets, what kind of assets we manage, what kind of condition these assets are and based on that, what kind of programs which have been covered. I want to touch base on some of the performance comparatives which have been used in the past and performance comparatives which are currently under development. These were the performance comparatives used in Ontario Hydro retail utilities. Up until the end of 1997 we had eight retail utilities and each utility was managing their performance and essentially some of assets were -- the indicators which were used, one was to measure the reliability of the system. Presentation 828 (V. Suri - SERVCO) Two measures, which could be SAIDI, which is system average interruption duration index; CAIDI which is a customer average interruption duration index. Then essentially the frequency also measures, which is SAIFI, which is system average interruption frequency index. Some measures to look at the delivery of the cost which is cost per megawatthour and kilometres, asset cost, cost per gross fixed cost. Asset cost means the cost of maintaining and replacing the assets. And planning and performance indices. We have been looking at these performance indices which were used in retail and trying to develop some indicators for the distribution system. What we have found in the past is that the formula, the methodology, data collection which was used in different utilities we had different methods for that and unless and until we have a consistent approach, at this point in time what we will do is -- these indicators still are going to be in a further development stage. We also looked at, in the past we have been participating in some level of distribution benchmarking and early indications which were given to us in 1997 that the distribution costs were average and reliability was slightly below average. This is compared to some of the benchmark utilities which were used in the benchmark, but the difficulty, again, looking at the benchmarking information also is how we have collected the data, how the benchmarking utilities have collected the data. Presentation 829 (V. Suri - SERVCO) The people who, the experts on the performance measurement who we are dealing with are saying that the distribution benchmarking is where transmission benchmarking was four years ago. So really, there's a lot more that needs to be done on the distribution side because the utilities have not unbundled their cost for distribution to the extent that they have unbundled transmission and the data is really not comparable in many, many cases. So there have been some caveats given to us saying that we should be looking at it and standardizing it. Work is continuing. Obviously we are developing performance benchmarks, performance measures for the distribution system and I have a slide on that which are the performance benchmarks. Before we get into that, I just wanted to give you an example of some of the distribution service standards which are also under review. The part of the things we are looking at is like what kind of service standards you offer in addition to the voltage fluctuations and other things, like from a system perspective. The examples which have been used in the past by some of the utilities and are being considered at this point in time is a new or upgraded customer supply, that if you ask for a connection or a house or cottage to be connected, that after the inspection, the connection can be completed in five working days. Similarly, keeping an appointment, we're all Presentation 830 (V. Suri - SERVCO) aware of it, when we make appointments, that a.m. or p.m., within two hours that we will be there. A request for us, people are planting trees or digging holes in the ground and they want to look for where the cable is and those requests could be handled within two working days. It's a nature of the some of the work which is currently being done, by no means we are there as yet, but certainly I think these are the areas we are looking at from a service standards point of view to the customers and also dealing with performance measures. Let's come back to the performance measures which are currently being developed. As I indicated, the benchmarking results were available, become more available as utilities unbundle and distribution data becomes more readily comparable. The two key areas of measurement which we are considering looking at this point in time: one deals with the cost of distribution; the second deals with the reliability of distribution. And on the cost side, it's a total of OM&A and capital expenditures divided by the megawatthours flowing through the system and multiplied by the kilometres of line. And the second is OM&A plus the capital expenditures expressed as a ratio of the net book value of assets which are in service. Similarly, from a reliability of distribution point of view, essentially looking at two indices: one Presentation 831 (V. Suri - SERVCO) deals with the duration; the other deals with frequency. It's SAIDI and SAIFI. And I've indicated that we are looking at the data collection, what kind of data points should be used. In looking at the duration of interruptions, you are looking at the time taken by when the call is received from a customer to dispatch a crew, you're looking at the travel time, what the crew takes to go to the trouble site, and you're also looking at the time actually it takes to fix the problem and then fix a problem would be as -- if the problem may be on the customer's secondary side. So these kinds of decisions really need to be made, what is the formula and so on? And as I indicated, the data from other utilities and within our own retail utilities really was not totally comparable and we are in the process of reviewing that and developing some appropriate performance measures for that. Okay. I'm on the last slide which we will deal with the conclusions of the capital program. As I indicated, programs included in the forecast deal with sustaining capital, deal with development capital, operations capital, capital for customer care. The program also replaces -- will replace a number of assets. The example would be, is 23,000 poles, 11,050 kilometres of conductor which are going to be replaced in there. It's a total of all the programs. We have specific pole replacement programs, but when you relocate Presentation 832 (V. Suri - SERVCO) lines, you replace poles. When you are connecting new customers, you may be replacing some poles at that particular point in time. So the majority of the programs, what happens is when you deal with them you replace poles, conductors and everything else. The idea also is to look at the condition of these assets. And because you have a structure there, the ideal situation would be that if you have a pole which needs to be replaced, you've got a conductor which needs to be replaced and you have an insulator and a wood pane in the same pole needs to be replaced, that that work gets done at the same time. So development of the information about the systems is becoming more and more critical for us and the program provided -- dollars provided in this forecast certainly will address this lack of information needs for us. It will help us automate some of the data about the assets. Not only will it produce a registry for these assets for us, but it will also give us a means of finding out who is connected to what assets and help us manage the outages in a much more efficient and effective manner. And certainly the capital forecast, as I mentioned, does include a lot of demand kind of capital. And the demand capital is, really is because the customers, because we're supplying electricity to the customers, customers say 'I need to be connected' and essentially we just deal with the connection of those customers. The customer says that 'I need my service to Presentation 833 (V. Suri - SERVCO) be upgraded'. The Ministry of Transportation of Ontario or a municipality would say that we are widening these roads, 'you need to relocate your lines and relocate your poles', and those are the demand kind of programs which essentially are a normal part of the distribution system in which we deal with that. And with that, I think this concludes the presentation. The rest of the presentation which is in your package, as I indicated, we will be covering it as part of the OM&A Panel tomorrow. And at this point in time, the panel and I would be happy to take any questions. MR. HARDY: Actually, thank you for your presentation. I think at this point in time I'm going to call a break and we'll break for about 15 minutes. On my clock, that brings us back about almost 15, 17 minutes after 10. Okay? So we're adjourned for 15 minutes. ---Recessed at 10:04 a.m.. ---On resuming at 10:20 a.m. MR. HARDY: Okay. Why don't we resume? In terms of the procedure, we'll start with the Board Consultants, Board Staff, posing their questions. They'll probably have questions all day long, but we will ask them if they can find an appropriate break sometime in the morning, so at that point we can allow some participant questions as well. So Board Staff Consultants, you can lead and [Questioning] 834 Board Staff/Consultants we'll be looking for a break, say, about an hour from now, 45 minutes or so. Why don't you begin by introducing yourselves and then we can start with your questions? MS. LITT: Kathi Litt, Ontario Energy Board Technical Staff. MS. BULKLEY: Ann Bulkley, Reed Consulting Group. MR. HOPKINS: Bill Hopkins, Reed Consulting Group. QUESTIONING BY BOARD STAFF AND CONSULTANTS: MR. HOPKINS: Thank you for you presentation this morning, it was quite helpful, and I realize that your presentation goes to some of the questions we have been asking along the way and it was very informative. Q. We've asked some questions previously that I may ask again this morning and I hope that you'll bear with me, but they do help to introduce some of the material that we're into. Looking at your capital programs, I guess I'd like to start with -- to go back to the concept of the network management, asset management organization, just quickly and see if my understanding is correct as to how it's operating. The network asset management organization will have two separate pieces; is that correct? MR. SURI: A. That's correct. One would be for distribution and one would be for transmission. Q. As you've outlined here, we have the [Questioning] 835 Board Staff/Consultants distribution piece of 105. Does the distribution piece share any of their operations with the transmission; is there any shared functions? A. There are functions like performance management, functions like regulatory affairs which are common at the network asset management level and those are the functions which are shared. I think in the submission we talk about a total number of 481 people in the network asset management group. Out of that, 105 are in distribution, but there are common functions which were allocated to transmission and distribution. Q. What would be the direct number for the transmission; did we get into that at all the other days or do you know? A. I do not have that number. We can certainly look into that. Q. And then there would be this balance that would be common; is that -- A. That is correct. Q. -- is that the concept? A. That's correct. Q. do you have some outline maybe similar to this as to what those common functions and staffing would be? A. Okay. We can -- you know, I can look into that. [Questioning] 836 Board Staff/Consultants Susan, you may know that. MS. FRANK: A. There's a bit of a -- actually, I think this line of question is similar to what was asked previously of us and we had at that time agreed to provide you with some material and I believe that material is on its way within a day. But trying to answer at least the first level question, the material that was filed on December 23rd had a staff breakdown showing the network asset manager - this was the December 23rd tab A material - and in there, Table 1 shows a bit of a breakdown, asset manager network services, that type of level. Now, I think your question, though, Bill, goes further than we showed in that table, goes to what was in the network asset management group. And you've heard on Transmission what was in TNAM and this morning you've heard what's in DNAM and the rest of the number is the support function and it's roughly, 70 people were in the support function at the time we prepared this submission. I think one of the pieces you were asking for was the change in organization that we've shown from what was the basis of the submission versus the piece that Rod Taylor showed, the new organization that we're operating under, and that note will cover, will cover that piece. Q. That's helpful. I think that would be helpful to us putting all this in context. MR. HARDY: I understand that that first part of your question has been responded to, so I don't need to [Questioning] 837 Board Staff/Consultants make a note that there's -- except for the information that we've already noted as coming forward-- MS. FRANK: Right. MR. HARDY: --there's no additional information that's being expected? MS. FRANK: I'd suggest you take a look at what you get. MR. HOPKINS: Yes, okay. We may have some additional questions, particularly if relates to how the costs were split and the common functions as well there. Q. It may explain that or it may not. MS. FRANK: A. This piece was directly a staff piece. If you're asking about the cost allocation, that would go back to the piece -- once again on Panel 1 we talked about the allocation of common costs and how they were done. The OHSC overhead costs as well as the costs that are support function costs within the NAM would have been allocated on the same basis, so if you'll go back to that. Q. One of the things that the distribution network asset manager has to deal with is the level of expenditures that can be carried out at any one point in time. Could you elaborate in any way as to how that's determined by you or how you see that being determined as you go forward? MR. SURI: A. The level of expenditures are determined by a number of factors. When we are looking at [Questioning] 838 Board Staff/Consultants -- take the example for development capital, we will look at number of housing starts. When we are looking at relocations, we will try to get some intelligence from the road authorities and municipalities, that where do they plan to widen the roads. When we are looking at service upgrade requests from the customers, we will look at historical data, on an average how many customers are looking for service upgrades. Based on that, then we will arrive at the capital which is required for development of the new system facilities. Similarly, on the sustainment one, essentially is driven by looking at the condition of the assets that I explained, what condition these assets are, and what kind of replacement programs we need to be getting into, how many assets are we getting into, into a category which is exceeding their expected age, that's a starting point, and then we start specifically go and identifying these assets. We have also looked at the failure rates of these assets. We look at the number of outages which come from, or complaints that come from the customers. So those factors are rolled in. And then the other part would be, is looking at the overall load growth in the area, overall customer growth in the area, and the plans are made. Q. You also have the operations capital programs as well which are basically, I take it, just part of the restructuring of the organization? A. That is correct. Operations capital programs [Questioning] 839 Board Staff/Consultants really are, as I indicated, are the new programs and because we are implementing this integrated GIS and outage management system which will help us to manage the outages in a more proactive manner which would help us to dispatch crews in a much more effective manner, give us the information from a planning perspective what the condition of these assets are and the age. So it served as an asset registry for us and the kind of work which is being done on these assets. So that would be an expenditure which we are indicating will be for the period 1999 and the Year 2000. We're not expecting this level of expenditure on the operations side on an ongoing basis at all. There may be some modifications required to the system which we will be implementing, but it's nowhere close to $19-million which is included in the Year 1999. Q. In looking at all the capital programs that you could undertake, of course, is probably a fairly long list of things that might be appropriate to do, I guess one of the issues that I'd like to explore is, how do you prioritize this in a sense that there's a level that you can afford to undertake in a sense and how is that managed in this process, that the level of affordability of going into these programs in -- and maybe that level of affordability has a time sequence to it; what can you do this year, what should you put off until next year because it's going to cause financial stress within the organization? How is that managed? [Questioning] 840 Board Staff/Consultants A. The priorities are mainly set from an impact on a customer perspective. If we were to replace poles on the system or a conductor on the system and we were looking at replacement of low-voltage poles and rural poles, what we will do is, I think we will prioritize in a manner that we will fix the low-voltage system first. The concept would be the system which has the most impact on the customers, so you will deal from that perspective. From a priority point of view, we also look at the demand capital because we are in the distribution of electricity business, customers want connections, customers want facilities that they can have power and essentially those demand programs get into a higher priority. So basically expenditures are dealt with from a customer perspective because when the capital is also being looked at, it's really looked at what the failure rates are going to be, what impact it's going to have on the customer. So that's sort of a broad principle which gets used in setting up the priorities of the capital programs. Q. Okay. So as we look at the programs you're presenting here, this has gone through some sifting within your organization at this point to look at the programs in that -- from that perspective for the years 1999 and 2000 that we're seeing here? A. That is correct. Q. And it's been balanced against, obviously, [Questioning] 841 Board Staff/Consultants these criteria and as well with what can be afforded without putting, you know, the organization in a point where it's going to have to raise its prices or lower expected income as well? A. That is correct. I think we've looked at the priorities of capital expenditures within the Services Company, within the distribution system, and these programs have gone through that review. Q. As we look at this idea that we've described capital programs that we have planned for the coming years and we want to have financial integrity as well exist in those years going forward without having to change rates or prices significantly and we're basing our requirements somewhat on expectations, what would you do if -- what are your ideas with respect to the fact that you don't spend what you've anticipated you've forecasted here or you've overspent what you've anticipated here? What would be your thoughts on that matter? How will that be handled or how are you proposing to deal with that? A. The capital expenditures which we are forecasting at this point in time are essentially designed, as I indicated, to meet a lot of the demand requirements. So demand capital certainly would be -- if the demand doesn't materialize, we have estimated that we will connect 16,000 customers or up to 16,000 customers next year. If for any reason we were connecting 14,000 customers or if the customer growth exceeded what we had planned for, certainly what is in the capital dollars for [Questioning] 842 Board Staff/Consultants these things are estimates. These capital -- that's why on the distribution side we call them all programs and not projects, because each one of the activities of customer connection becomes a project in itself. Obviously you're dealing with assumptions about what will happen in those forecast years and the fluctuations do take place as the time goes on. We had years in the past where customer growth was more than what we had forecasted in our planning processes, and then if you were to be within the capital outlook which was approved for individual utilities in the past, they will drop some of their replacement programs. They will set their own priorities. Again, it's really -- the focus has been the impact on the customers and you set the priorities. A demand capital customer asking for a service upgrade, a customer being connected is a critical one. So instead of 16,000 you connect 17,000, we will go connect them. So there would be a priority set on a provincial basis. The advantage which we will have now is that we start prioritizing these capital programs on a provincial basis rather than on eight geographic locations basis. It gives us a much better way of managing the capital programs, and certainly there are a number of replacement programs which we have looked at which are going to be going beyond 1999 and 2000. We have identified that we will be replacing up to 23,000 poles. At the moment I don't know where these [Questioning] 843 Board Staff/Consultants poles are. The process you have to go through really is where these poles are. When we actually come to find out it maybe 25,000 poles we may have to replace. So there are fluctuations in all these numbers and essentially the whole process we will be going through on an annual basis would be as looking at what exactly it is. Once we start getting the information about these assets in a much more detailed manner as we are proposing through implementation of this asset management system, these fluctuation can be much more manageable because before we get into a replacement program, before I can go to network services and tell them to go do this, I have to tell them where. So there is some fluctuations in the programs and we will be setting priorities on a provincial basis. Q. As I understand the scheme of going ahead for the next several years, the distribution company, upon approval of its revenue requirement, will draw that out of the revenues received from the sales of electricity and some of the transmission company and then revenues will flow forward to other organizations, but those revenues that will be drawn out will be fixed. A. That's correct. Q. Are they not going to vary with sales, customers coming on line or not coming on line. They are going to be a fixed amount so that if you undertake a program -- if that budget number that exists for the [Questioning] 844 Board Staff/Consultants revenues you are going to get for the Year '99 and the Year 2000 is fixed, and that includes these programs which could vary, what becomes of the revenue that would otherwise have been attributed to that program for those years? Is it excess earnings? Is it passed through to another organization, or is it -- would we consider a deferral account for that to be handled in some fashion? I guess I wanted to explore your thinking on that. A. These are capital programs, so the impact from a revenue requirement point of view would be when the assets come into service as to depreciation and interest. Q. Absolutely. But you have some OM&A. I guess it's a question that might also apply to the OM&A, but I thought I would bring it up as a sort of a global question. The capital programs add to the cost of service-- A. Sure. Q. --and if they are not undertaken, then the cost of service, the revenue requirement vary. A. The type of performance contracts which are being developed within the Services Company is that a person like myself and others are going to be compensated for delivery of certain results. So the concept would be that you are accountable for delivery of performance against these assets. As I indicated, we are developing the performance measures and so on. [Questioning] 845 Board Staff/Consultants The concept would be the programs need to be developed to deliver that results or the outcome. And it would be up to the asset managers to look at that. Certainly if I needed more capital I will have to go back to the executive team within the Services Company or Services Company board and talk about implications of not carrying this extra demand capital. If we required less capital, in which my experience has told me from the time I have spent in distribution that that day hasn't arrived as of yet, looking at some of programs which we have here, looking at the condition of the assets, personally I do not think that we will be requiring any less capital for these programs. Most of the programs we are really looking at are really very, very in a stage where they are competing priorities. They are all high-priority programs because when you are dealing with assets which are deteriorating or dealing with a customer who needs to be connected or dealing with a computer system which needs to gather the information about that, I think we are placing equal priorities for that. So at this stage I'm not even forecasting a situation that I would need less, but certainly a situation can be that you would need more. In the past in retail utilities what used to happen was that they will, if the demand exceeded they will drop the sustaining capital programs because if there [Questioning] 846 Board Staff/Consultants was a capital ceiling given to a detailed utility manager saying 'This is your capital and budget and you will not exceed that capital outlook for that year', the utility manager will basically start setting the priorities from a development point of view and then get into -- because at that time we did not have any operations kind of capital. So really it was sustaining our development, like demand capital or sustaining capital. MR. HARDY: I've heard the question asked twice. I'm not sure if we are getting to the nub of what the question is. I am wondering whether it is something that should be passed to the next panel in OM&A or, Bill, whether it needs to be restated in another way? MR. HOPKINS: I understand the management of funds and that they have to be forecasted reasonably. Q. I guess because we are dealing with a fairly unique circumstance where the revenues to flow through to the distribution company are fixed for under this proposed process, and some of these programs will have some variance, as I think you've pointed out. You've said that you are at the early stages in some of these programs as to understanding the replacements or remediations that are needed and that type of thing. I think you probably have a better handle on the kind of additions that come forward every year and the replacements of other things that might be taking place due to relocations or other things of that nature. [Questioning] 847 Board Staff/Consultants But this condition assessment program that you set forward anticipates a certain level of spending, and I guess, because it then becomes fixed in part of the revenue streams, I was wondering what happens if the moneys are found not to be needed and whether or not they would be spent on the next prioritized program or there would be some decision to hold them in a deferral account for reprioritizing over the next year? MR. SURI: A. The condition assessments which were conducted at the end of 1997 and the amount of funding which have been included in this forecast, I think condition assessments would indicate probably a higher level of funding. The level of funding we are going with at this point in time is to really look at some of the uncertainties, as I have said, that the condition assessment generally deals with the age of the assets and makes some assumptions about those conditions. We actually have to go and identify those assets where they are. So if hypothetically if any money was left over, which I don't think will ever be the case in at least the next two-year period, then the condition assessment certainly indicates a lot higher level of spending which we should be really including in the forecast. MS. FRANK: A. If I could just -- I think that we are on the part of the capital program where we feel quite strongly that our estimates as to what the cost is [Questioning] 848 Board Staff/Consultants is, if any, is low. This work is absolutely essential. The part of the capital program that we feel is more variable is likely the demand part because we've made an estimate on the demand part and it's our best estimate given our experience in past, but as Vipin suggested, who knows if there is more customers who might want to connect or there is less. That portion of it indeed could result in a variance from what we have got in here. Actually, Bill, you go to one of the reasons that we are very interested in pursuing, a PBR formula that is price oriented, because if we went with the price cap PBR, any changes in the level of customers' requests could be affected in the revenue requirement in the future. So, you know, it's a good reason why you would consider that. But certainly it is an issue in terms of how much we've got for demand capital, if it is either higher, as more customers connect, or less, as fewer customers connect. How do we do that and how do we address that in this application? Certainly my reaction would be it would be up to the Board to make some comments on that. MS. BULKLEY (Reed): I would just like to revisit a couple of things that you mentioned earlier. Q. You first indicated, and maybe this will be helpful in our understanding of your spending needs, you indicated that some programs have been projected beyond the Year 2000, any expenditures necessary have been forecast out for longer periods. [Questioning] 849 Board Staff/Consultants Can you give us a sense of which programs those are and the values that you are looking at? MR. SURI: A. I don't have all the future numbers here. Offhand, the DOMCAMS program - not DOMCAMS - the SCADA program, I'm sorry, has some expenditures in the future years. I can certainly look at the number and if I have it available I can provide that. The pole replacement programs, conductor replacement programs, asset condition programs, they will all get into future years. It's the operations capital which is a new category. The DOMCAMS to the extent of the capital finishes in the Year 2000 and the SCADA goes to 2001. And other programs for sustaining and development will all carry into future years. Q. And those projections have been made for future years? I guess what I'm trying do is get a sense of we have got sort of a year of some historical information here which indicates, based on the chart that you put forth on page 14 of your presentation, that not a lot of asset condition restoration work was produced in '98. So I've got really no benchmark there and then I've got some pretty steep expenditures in '99 and 2000, now I understand that there is a plan going forward. I just want to understand the magnitude of the numbers for '99 and 2000 as they relate to your plan going forward. MR. SURI: In general, the capital programs, the [Questioning] 850 Board Staff/Consultants cost of the capital programs will be decreasing in future years because we have a number of other initiatives going on which is the re-engineering of all the business processes, implementation of the DOMCAMS which will start bringing in the efficiency improvements which is supposed to bring in the labour productivity items, which we are. So not having in the numbers here for the future years, the general sense is that we're not looking for a major increase if future years in capital programs. The cost of the capital programs will actually be coming down. Q. Would the company be willing to provide that information? I think the programs that you mentioned are more in the operations-related areas. I guess I'd like to know that sort of going forward I can look at all of the programs and say, you know, in 2000 you are spending "x" and that number projects out over a certain number of years and it's steady or it increases for various reasons decrease for various reasons. Is that information given that -- you seem to indicate anyway that there were projections available. Is it difficult for the company to provide us those projections just so that we can evaluate the magnitude of the expenditures? We don't really have much to go on in '98 here. MR. HOPKINS: Q. Or see the payback. Maybe you see the payback for some of the operations improvements you are making? If that's also part of it. [Questioning] 851 Board Staff/Consultants MR. SURI: A. I will consider looking into what we have available. Certainly I think these future forecasts, future programs will come next year in front of the Board when we were looking at the future years. But let me consider what we have here and see what can be provided. MR. HARDY: I will make a note of that then, that that information may be coming forward. MR. SURI: Yes. MR. HARDY: Thank you. MR. HOPKINS: Q. A number of the programs that you are, you know, looking at relate to this asset condition assessment that was carried out in 1997, I believe? MR. SURI: A. That's correct. Q. I thought I heard 1977 at one point. A. 1997. Q. Maybe it was just me. Is that an internal -- that was an internal assessment, right, carried out by you all? A. There were two parts to the assessment. One was an internal assessment and on the first, which is the OM&A program which we will talk about tomorrow, vegetation management, that was an external assessment. So we had done an internal assessment on the assets, but vegetation management was an external assessment. Q. Are those kind of analyses available for review in anyway? [Questioning] 852 Board Staff/Consultants A. I think we have prepared a summary of all the assessments which, my understanding is is being forwarded to the Board and should be available, actually I can check, either sometime tomorrow or something like that. MR. GILLESPIE: I believe those will be available tomorrow. MR. HOPKINS: As I've mentioned, we've asked for things before, but I just want again to put things in context, that these are somewhat of the underpinnings of some of the programs that are being put forward here. We would certainly like to see the nature of those. Q. With respect to the assets that are being transferred to the Disco, have those asset transfer orders been cut or whatever they are? MR. SURI: A. I didn't follow the question. Q. Are the assets that are being transferred from Ontario Hydro to the distribution company, if you will, or the Wiresco, have those assets been -- has that transfer been defined in total? Are there transfer orders or a transfer document been decided on? A. I'm not sure about the status of the transfer orders, but the assets which are to be maintained by the distribution company, I think we have a clear understanding of how many poles, how many transformers and so on and the plans are based on that. I'm not sure exactly what the status of transfer order is. Q. Those are net book value transfers? A. That's correct. [Questioning] 853 Board Staff/Consultants Q. That's correct. So what's on the books has been given to you as capital that you are going to have to manage and the amount of it is there. What would be your thinking with respect to if some of those assets were found to have no value or limited value, value below the value that's been transferred to you? A. I'm just thinking of what could be those assets. On the distribution system, the majority of the assets are poles, transformers, conductors, there may be some buildings there which may be surplus to our needs, and if there are some assets which we found that were not required, I think they can be disposed of. And if those values -- assets did not have any value in a sense, then proper, you know, accounting adjustments can be made. Q. Is that what you think you would do, you would do some form of assessment in the near term that would look at the value of those assets from running the distribution asset business, if you will? MS. FRANK: A. We did a careful examination of the assets and what was there when we looked at capitalizing our business and conversations that we had with the province in terms of what the assets were and what value the assets had. And last year at the end of 1997, we did identify some retail buildings in the field, service centre type [Questioning] 854 Board Staff/Consultants buildings that were surplus to our needs, and at that time wrote some of those assets off. So I'd say we've already done a pretty careful look at all the assets that are in the distribution system and identified that, indeed, there is value; the net book value that we have is appropriate for these and they have going-forward benefit to us. The small amount that didn't, as I say, were some of those buildings in the field were service centres that we were closing down since we didn't need them once we'd merged and we've taken care of those. I'm not aware of anything else that will be in the distribution system assets that we're now saying 'Is that of questionable value?' Q. Thank you. I'm looking at your capital budget and there is a large increase as you showed on page 14 of your exhibit here relating to asset condition restoration. That's a fairly significant item of expenditure. And I'm struck with the fact that as I look forward in that, look at some of the age profile details you give, like for low-voltage conductor and poles and raw conductor, transformers, et cetera, I look at the age, the profiles that are there, and it seems like there's a very low level of equipment that was installed in the periods 1995, 1994 to 1996. As you look at those bars on those charts, you see -- I mean, am I misreading it, that that's what was installed in those years as I look at, say, the charts on page 16, 18 [Questioning] 855 Board Staff/Consultants and 20 and 19...? The kind of equipment-related charts, I see circuit miles being, you know, fairly uniform -- well, I don't say fairly uniform, but more uniform in years pre-1994 and pre, you know, almost -- there seems to be such a marked difference of '94 onward. What is the nature of that? What was that about? MR. SURI: A. I think that you're correct, that the chart indicates how many poles, what conductors were installed during that period. What it indicates really is that we did not replace as many poles in that period as we did in previous years. It indicates that perhaps there were other capital priorities within Ontario Hydro with the result that when the funding was approved for these particular programs or the demand capital may have changed, so this does not give a total picture, but it does indicate correctly what was the number of poles or kilometres of conductor which was replaced. So certainly I think we probably were looking at different priority setting. Q. Some of these are demand capital items, those line transformers, conductor -- part of the conductor is part of poles as you mentioned, so the demand -- if you get a new customer, you have to put up a transformer, you have to add some wire, you have that type of thing. Would this sort of reflect what would be the demand capital portion of expenditures or...? MR. D'ARCEY: A. If I could perhaps -- in through the late '80s and in through the '90s, we saw [Questioning] 856 Board Staff/Consultants substantial growth on the distribution system. It tapered off then in through the '90s through conservation programs and the like. We were installing up to 50,000 poles a year back in through the early '90s. A shift in growth, a shift in capital expenditures has dropped that down to below 16,000, new pole installations in through the mid '90s, and I think that's kind of reflective of a trend that changed both within the company and both within load profiles. Q. Well, it certainly seems a marked difference from prior years occurring about that time frame. I'm trying to see if -- is that load growth still ongoing? A. No. The load growth tapered off in through the mid -- the early '90s. Q. And that's what you would be now projecting more or less to continue? A. That would be correct, yes. Q. So would these levels of circuit miles being added and service transformers being added as reflected in those years be sort of the demand level that you...? A. We were still under policies which were more along the lines of electrification of the Province of Ontario where there were large subsidies provided to people for extensions of the lines as well. We would build up to a kilometre of line at no charge to the customer. I think the policies have changed. We are reflective of what the customer pays for or has private [Questioning] 857 Board Staff/Consultants contractors install those lines, and are reflective, too, of the policy changes in through the early '90s, too, as well. Q. With respect to - and we'll want to get into the depreciation issues maybe a little bit more fully - but with reflection as you look at retirement, you know, you mentioned the age of the equipment driving a number of the programs and what have you, as I understand it, does your age program -- you reflect expected normal lives here of 35 years for transformers or 35 years for poles and that type of thing. Is that expectation based upon some industry standard, or is that expectation based upon some analysis you've made internally and is that analysis based upon your actual retirement experiences? MR. SURI: A. It is a combination of both. We depreciate these assets over the expected life as shown on these charts. As was indicated in the earlier panels, there is a depreciation review committee in the corporation which reviews basically the expected life which is a combination of the industry experience and what you're facing. And from a distribution system perspective, when we look at the replacement of these assets, essentially age is the first indicator for us saying: If the assets have aged, do they need to be replaced? It depends on a conductor. The loading on the conductor is not just an age, so you're dealing with averages here. [Questioning] 858 Board Staff/Consultants The concept here would be, is, when the assets have reached their expected life, you go and look at the condition of those assets and then make decisions about replacement and maintenance, but these are based on industry as well as the experience which we have which the depreciation review committee looks at it on an annual basis. Q. They look progessively at, you know, the age and the retirements occurring on the system, over time they've looked at your own actual experience by proper type of property? A. They have the information about the assets and the retirements. Q. Well, one of the thoughts that came up, and I'm backtracking for a minute, was, with respect to regulated utilities here in the province, in the gas industries, perhaps before the Board here, they've sort of adopted an approach for capital projects, budgeting projects, that sort of recognizes a spending level, if you will, and leaving the choice of individual projects in that spending level to the utility. Do you think that's something that would be implementable for you in a sense as opposed to, you know, having to, you know, add up these programs and judge each one of them as absolutely necessary, you know, what a capital spending level would be ... your looking at? A. My view would be, that one of the regulatory options is the performance-based regulation. And if [Questioning] 859 Board Staff/Consultants you're looking at the outcomes and certain results to be delivered from there, to impose any sort of arbitrary ceilings may result into a situation where you are not replacing assets and you may be making some uneconomic decisions. And the concept would be that if there is a price cap, there are clear expectations about the performance of these assets and certainly the programs can be managed by the utility because the priorities, the variables, the planning assumptions will change from one year to the other and -- but if capital constraints were placed on, then certainly you are into a situation saying: What can you afford in that particular umbrella? MS. BULKLEY: Q. How is that situation any different from the situations that it appears, from my evaluation of this application anyway, that you were under in '98 where maybe a small amount of capital was invested in asset condition -- asset recondition, I guess? How would the scenario that Bill Hopkins put forward be any different than under your own board scenario where you have -- you may take ten programs to the board and they say no; you know, you have to make that choice under that scenario as well and it seems as though you've done that in the past. Do you see any difference in that? MR. SURI: A. Well, it's still at the discussion of the board and especially coming back to '98 we had very unique situations in '98 because of the ice storm, so the board had approved expenditures, capital expenditures, [Questioning] 860 Board Staff/Consultants which need to be occurred to take care of the ice storm. We do make provision in the capital programs and also OM&A programs, assumptions about certain level of storms. We don't have ice storms every year, but we have lots of storms, wind storms and other things coming on. And certainly when those situations do occur, the part of the system which was in place in old Ontario Hydro was that we can certainly go back and talk about variances in capital as opposed to saying that these are absolute ceilings of expenditure. MR. HARDY: I'm looking for an appropriate point to break, so if ... MR. HOPKINS: I had a general question on the performance indicators and maybe that would be an appropriate place. Q. I wanted to go back to just the thought that -- what I thought you had said in the performance indicators that you outlined on page 27 of your handout, the SAIDIs and CAIDIs and SAIFIs, et cetera, that those performance indicators were being tracked - is that what you indicated? - by, let's say, the eight enterprises that existed? MR. SURI: A. They were using them to measure the performance of individual utilities. Q. Yes. A. And what we are doing at this point in time, as indicated on page 29, that we are trying to develop these four measures and defining what should be in the [Questioning] 861 Board Staff/Consultants numerator, what should be properly in the denominator, what should be the data collection points and try to standardize that and ... but different utilities have been using those indicators to a different extent using maybe a different collection methodology, so the results became difficult to compare and sort of inconsistent. This is the work we have been doing since the mid part of 1998 and trying to go through that and we have a performance management group which is one of the common groups in network asset management who is helping to look at the performance on the distribution side, also on the transmission side, helping us to look at the data from other utilities. And that performance group, as I indicated, have come back and said the data available for distribution is a lot less comparable than the data on the transmission side is. Many of the utilities have not unbundled, so... That's the measures we have and the utilities did use these measures, that's correct. Q. Just to be sure, there is a history of system average interruptions, customer average interruptions, system average frequency issues. Within Ontario Hydro, there is a -- you have your own data on this; is that right? A. That's correct. Q. Yes. And what you're saying -- you're suggesting is, it doesn't compare well with other utilities at this point in time? A. And it's not even calculated properly because [Questioning] 862 Board Staff/Consultants each utility have used a different data collection methodology and, you know, when you look at the system outage duration index and so on, the variation could be anywhere from three-and-a-half hours per customer/per year to eight hours per customer/per year and which does not tie in with when we talk to customers saying, what is their perception of the outages and how we've been performing. So we've been trying to reconcile these numbers from -- which we have looked at from different utilities. So that data does exist, but really it's not making any sense at this point in time because it's collected using eight different methodologies. Q. I see. On page 29 you indicate that you're interested particularly in the measures, the two measures of cost and the measures of reliability, and the reliability measures you put forward are the system average frequency index and duration index. You've left behind the customer index. Was that intentional; and if so, why? A. No, I don't think it's intentional and perhaps this is not a full list. There are a whole bunch of other measures which are being looked at by the performance measurement group at this particular point in time. And I should have mentioned that these are some examples of the measures we are looking at. And certainly no decisions have been made that what measures are going to be used. Certainly, I think the board will make some [Questioning] 863 Board Staff/Consultants recommendations to us, that what measures need to be used, and we are reviewing those measures ourselves. At the end of the day, we will have a combination of measures which the Ontario Hydro Services board will want to use and measure the performance of the distribution system. The Ontario Energy Board may have some recommendations regarding the measures. So the list will be a combination of all. Q. I think we would be interested in the measures that you are considering and I don't know whether it's premature for to you share that with us, but I think we would be -- we would be interested in what those might be. If we can contribute our thoughts to which ones we would like to see you going forward with, I think that would be one way to do it, would be to look at what you're having some thoughts on. A. Okay. I will consider what those measures are and consider providing those to you. MR. HARDY: Okay, and I'll note that as well, that we're expecting that to come forward then? Okay. Q. One follow-up here. MS. BULKLEY: I just wanted to follow up. Q. You indicated that you had surveyed customers with regards to their perception of your performance. Can you give me a sense of what customers -- what feedback you got from customers? MR. SURI: A. I don't recall all the results of it, but I think the certain comments which we were getting [Questioning] 864 Board Staff/Consultants from the customers were that the customers' perception about the service levels which we were providing, you know, we were providing a good service to the customers. Certain parts of the province would indicate that we were managing outages in a proper manner. Other parts will indicate that certainly some of the results after the ice storm which we had heard from the customers, although no survey was done, and in a general sense, I think there was a satisfaction there, but they were concerned -- overall conclusions would be that perhaps we're not as much informed about whether the customers are out of power or not. Customers have had difficulty in being able to contact us in certain areas and ... So there was a general level of satisfaction if I could characterize the survey, but there were areas which dealt with issues with our response to the outage management or the availability to contact us properly. Q. The time that it took, the duration of an outage then, is the customers' concern; am I understanding you correctly? A. The customers essentially, from my perspective, look for when they are without power, that does utility know they are without power; and two, then they want to know when the power is going to be put back on. So their concern really is our inability to guess at or give them an appropriate time during -- actually, this happens in emergencies mainly rather than a routine one, is that when would the power be on? And I think one of [Questioning] 865 Board Staff/Consultants the common complaints from the customers were that we could not estimate in a proper manner the power is going to be on in the morning or in the afternoon. So that really was the issue from there. And which sort of goes back to, again, is lack of information which we have about the system and about the condition of the system. MR. HOPKINS: Well, thank you. We have a number of questions that deal with specific programs and specific items within those programs that I think we'd like to get into later in the day, time permitting, but I guess it would be time to have other questions. MR. HARDY: Thank you. MR. SURI: Thank you. MR. HARDY: At this point I'm going to open up the questioning to participants and I will repeat that anybody is available and free to ask any questions. Normally we start with the people at the mikes, so why don't we start with you. Introduce yourself. QUESTIONING BY THE PARTICIPANTS: MR. WHITE: It's Roger White and I'm with Energy Cost Management Incorporated. Q. I have a number of general questions. I guess the first one is -- anybody from the panel or whoever think it is appropriate can jump in with the answer. I heard in the presentation this morning a lack of confidence in what assets are in the field, and at the [Questioning] 866 Participants same time I heard that we know exactly what assets we're getting. Would you characterize what has been transferred to Disco as estimates of what assets have been transferred or are they truly hard numbers? MR. SURI: Susan, do you want to answer that? MS. FRANK: A. I'll deal with the transfer part. What gets transferred is what's on the books. So what we have is asset groups or categories that the asset would have been installed or purchased under and assigned to a group asset. So we would have a low-voltage transformation category of assets and all the assets that were purchased under that make it into the fixed asset system and get depreciated over time, additions and removals taken out and at the end of the period we have a net book value at any point in time. It's that net book value that gets transferred. The financial systems are not so sophisticated to have a by-transformer-by-transformer listing. They are pooled. So if you wanted to go to the financial systems and find literally what transformer was in what location of what vintage, the financial system wouldn't be very helpful. It's a pooled account. So what we have got from the financial system is a total asset value of all those pool accounts. I'm confident in that. I think what Vipin is talking, and I'll pass it [Questioning] 867 Participants back to Vipin, is physically where those transformers are and which transformers and financial systems can't help you now. MR. SURI: A. I will just to add to that. I think what I was indicating was we do not know, if he said how many poles need to be replaced, where these poles are, but how many poles, the physical assets, certainly in total that number is there. These are hard assets which have been transferred to distribution. Q. I'm sure there are people on the panel who are aware that a number of municipal electric utilities in the province are expanding and assuming responsibility for many Ontario Hydro assets and former Ontario Hydro assets and customers. Would it surprise the panel to know that in every case where a field inventory has been done that the field inventory price is over 10 per cent below what the initial estimates prepared by Ontario Hydro were for what the estimated transfer price would be associated with those customers? If so, what implication should that have for the Ontario Energy Board with respect to your rate base? A. Okay. I am aware of the annexation activity or boundary expansion activity for the municipal electric utilities. When we do some annexation studies, at that point in time the assets are estimated based on a fixed dollar number by customers being transferred, and it has been [Questioning] 868 Participants typical of any annexation studies when the discussion starts saying: What is the estimated value of your assets?. It is really determined by saying a fixed dollar value per customer which are going to be transferred. That is followed by actual inventory taken of the assets. My understanding, Roger, is that you are defining that the difference between the estimate and the actual inventory, and because the estimate is not even based on -- because we don't know how many poles exactly in that -- the records are not kept by the boundaries which are being transferred over to the municipal electric utilities, so really we estimate by saying number of customers. So those study estimates can be use by municipal electric utilities to talk to their commissions and counsellors and you're correct, yes, there have been variations because it's an estimate or value derived at making some assumptions. Q. Is there any reason that you can attribute for why in all cases the estimates would be high compared to the actual field inventories? A. I don't think in all cases the estimate was high. We have a case, the name escapes me, is where we have gone back to the utility and said to them that the assets being transferred are more than what we have estimated. So it is not the estimates were high in all case. Q. One in twenty then? [Questioning] 869 Participants A. One I'm aware of. In all other cases we have not completed the inventory of the assets, so I really don't know what the results are. Q. In terms of establishing the priorities for capital work, you indicated that the prime driver would be customer, and I'm assuming whether you are talking sustainment capital or demand capital, when you use the word "customer", do you use the word "customer" in the same context as the Ontario Energy Board has the word "customer" in its statute, that it has a duty to protect customers and that includes all customers in the province including customers of municipal electric utilities which Disco is supplying? A. In the context that when you are developing programs it is the customers who are being fed from the distribution system and these would be customers, like I indicated, 202 municipal electric utilities, 960,000 retail customers and 45 industrial customers. Q. So when you talk about "customers", then, if the customer is a municipal electric utility, that they get a count of one in terms of the priority formulas where three rural customers get a count of three? A. I don't think the programs are developed like that, that we count municipal electric utilities as one customer. But it's the impact, if you want to look at it, from an overall -- in that context, perhaps then from an MEU customer perspective would be is the end-user. What [Questioning] 870 Participants is the impact on the whole municipal electric utility? A municipal electric utility, as you know, are serving end-users at the end of their line and the impact on the municipal electric utility is going to be -- I think we will consider that as a large impact, then we will consider as connecting or replacing assets connected to one retail customer. So in that context it would be -- from a customer point of view, the definition which we use in distribution is the customers who are fed from the distribution system and those customers may have further impact as a result of the interruption in service and that is also taking into account. MR. HOPKINS: One example might be of what his question was, if I might jump in, where we talked about the customer interruption index. You know, how would his municipality be counted as one customer in the impact of that? MR. SURI: Yes. I think those are the things we are trying to struggle with, saying what should be in the formula and how do we calculate those duration indices. MR. HOPKINS: Because clearly there is a much bigger impact on that -- MR. SURI: That is absolutely correct. MR. HARDY: Thank you. Roger, continue please. MR. WHITE: Q. One of the comments I heard this morning was that the reason for this substantive reduction in capital spent in the latter years was a substantial [Questioning] 871 Participants change in the way that Ontario Hydro finances demand capital. Is that consistent with -- like, what criteria is used for the investment of Disco capital for demand customers? Is it the customer pays everything to the connection point and, if so, how is that capital treated in terms of the books of Disco? MS. FRANK: A. I was waiting for this question, Roger. Q. Thank you. A. I think you asked a similar type question on the transmission side. Actually, the customers pay for what their requesting in terms of connections and we're at the point where -- luckily my colleagues on Engineering can handle the equipment better than I can. I know we asked the customers to basically pay for the lines that are there. I think we pay for something called transformation and the meters and I... good. I'm getting nods that that's okay. The customer basically pays for the full lines that need to be installed to serve the customer and they make the entire capital contribution for that. It does not appear on our books anywhere. It's the customer's contribution. If the asset was built -- let's pick a farmer and it was built across a farmer's field that he owns exclusively, then he would continue to own that asset and [Questioning] 872 Participants would manage all future maintenance. If that asset was on a common roadway or a common use, then that asset would more typically be transferred to us for some nominal -- a dollar or two type transfer. I won't anticipate your next question. I'll... Q. What do you do with the prepaid maintenance on it? A. Okay. What happens with these additional assets that get transferred over is that we would maintain those assets ourself and not charge the customer it. That's primarily because we expect that there will be other customers coming along that roadway and connecting to it as well. It would be incredibly difficult to separate the maintenance down as over the next few years while the customers connect in. The other thing is the dollars are relatively small. However, a final comment is we're looking at this approach and is this appropriate for our going-forward future. If I was to move off my farmer to an industrial customer, it's certainly a question we are asking ourselves: What is the appropriate future treatment? We don't have trouble with the idea that they pay the capital up-front, but we are wondering if they should get a free ride on the maintenance in the future. So we're examining the future direction and we don't have that today. Q. I need a little bit of help just to make sure [Questioning] 873 Participants I understand what I think I'm hearing. What I'm hearing is that the distribution company feels that it should put no capital dollars save and except I think I heard "meter" and possibly "transformer" into the supply of additional consumers along its lines of rights-of-way? A. It's the new connection. When a customer wants a new connection we only -- that's as far we go. The capital we ask the customer to provide. MR. WHITE: Thank you. MR. HARDY: Thank you. Again, if there are follow-up questions sometime in the afternoon I'd be pleased to take them. Bruce, go ahead. MR. BACON: Bruce Bacon for OCAP. I just have a few questions with regards to your presentation. I will take you through it page by page actually. Q. Page 2, it says you are seeking approval of revenue requirement for distribution in remote communities. It is my understanding from the application that you are also seeking approval to use existing rates for the interim period to charge distribution customers; is that correct? MR. SURI: A. My understanding is that the rate approval for the distribution system or for retail rates, they have not come to the Ontario Energy Board in the past [Questioning] 874 Participants and we are at the moment still going by some of the sections of the Power Corporations Act. And the retail rates in the past have been approved by the Ontario Hydro board of directors, and so the reason here was that those rates still are going to be approved within Ontario Hydro. We are specifically seeking revenue requirement approval for distribution because the Services Company is going to come into existence on April 1st, 1999 and certainly in order for it to come into existence we will not be governed by the existing Power Corporations Act and we would need a specifically approval for distribution revenue requirements and a distribution licence. That's the purpose, it was my understanding. Q. Can you turn to page 10 of the application, please. MR. HARDY: December 7th, page 10? MR. BACON: Yes. It's the application. MR. HARDY: Thank you. MR. BACON: Q. In Section B it says -- Section A is basically asking for the revenue requirements which you have asked here. Does everybody have that? MR. HARDY: Sorry, I don't. MR. BACON: Sorry. In the application, distribution application, page 10. MR. HARDY: Right. Okay. I have to look at page 10 and not 11. Okay. Sorry, go ahead. [Questioning] 875 Participants MR. BACON: Q. Line 4 says: 'To distribute electricity in accordance with existing Ontario Hydro retail rates.' Isn't that seeking approval to use existing rates from the Board? MR. SURI: A. My understanding was we were not seeking approval. Perhaps, Michael, you have may have a comment on that. MR. GILLESPIE: That's correct. It is as worded, seeking approval to distribute in accordance with those rates. MR. BACON: That's not seeking approval for the rates? I am confused, but anyway... MR. GILLESPIE: The rates are already in existence, as Vipin mentioned, under the rate freeze and the requirement of this -- this gets into a range of legal issues which we weren't -- well, the requirement of the legislation is that you need to have an order of the Board in order to distribute and that's why that reference is in there because there is a requirement to distribute in accordance with the rate. MR. HARDY: Michael, could you introduce yourself for the participants as well. MR. GILLESPIE: Sorry, Michael Gillespie. MR. HARDY: Thank you. MR. BACON: So is what you're actually saying is that we should read this as to have a period after the word "electricity" and ignore the rest of that sentence? [Questioning] 876 Participants MS. GILLESPIE: Sorry. MR. BACON: Like... MR. SURI: I'm not sure which line are you looking at. MR. BACON: Line 4. MR. SURI: Line 4. MR. BACON: It says "to distribute electricity". So you are basically seeking approval to distribute electricity. That's what you are asking for? MS. GILLESPIE: No, it says as stated "in accordance with the existing rates". MR. BACON: Okay. Some of my other colleagues may want to pick up on that one because it looks like you are asking for approval of the rates, but I'm confused so we'll go on to the next question. MR. HARDY: Yes, I think so. Again, I've heard this three times now, and certainly later on in the afternoon if there's a reformulation of the question or some rethinking or the panel wishes to provide further clarification on that, I think that would be fine. Again, I'm hearing a fairly consistent response from this panel to that question, so let's move on to other questions. MR. BACON: Okay. Q. On page 9, you mentioned the -- page 9 of the presentation, the second bullet, operational excellence, you list three categories there. I sort of asked the same question of Ron Stewart, so it may be the same answer, so ... but I just thought I'd ask this panel as well. [Questioning] 877 Participants How do you plan on measuring those three items, specifically: redesign of business processes, labour productivity and customer responsiveness? MR. SURI: A. The individual process measures at the moment are also being developed along with the system performance measures and we have various teams which are in place and implementing the redesign processes. And the concept really would be at the end of the day, we will develop indicators, that if you implemented a new outage management process, that one of the indicators could be, is, what's the cost of managing an outage, how much time do we take to dispatch the crews after a customer notifies us, and those are the kind of measures which are currently being developed and we will measure that thing, that once we have implemented these processes, what are the costs. At the end of the day, I think it will also be looked at saying that if you are connecting so many customers, what has been the cost previously, what is going to be the cost tomorrow, and... So there are going to be a series of performance measures for each process which is being developed. Q. Do you have any idea what the customer responsiveness measure will be? A. Customer responsiveness measures also deal with -- in one of the slides I talked about service guarantees or providing some distribution service standards. It's page 28. Some of these ones would talk about from a customer responsiveness point of view. [Questioning] 878 Participants Customers say that I need power and how long do we take to connect the customer and those are the kind of measures which are also being developed at this time. Q. Okay. Page 14, please -- actually, page 13, I'm sorry. Now, this is a question that we may have to talk to Graham about when he comes in tomorrow, but I'll ask it now. Specifically it's on customer care capital and -- it's actually on customer care costs. We can deal on OM&A tomorrow with it, but it doesn't matter at this point. In the application, you're suggesting that there's going to be at least two subsidiaries in OHSC, specifically Wiresco and Supplyco. We can turn to it, but it's right in the application. The customer care costs essentially are for the call centre and the billing. And I am just wondering, down the road - it may not be right today or even in the interim period but where do you see those costs going? Do you see it in the Wiresco subsidiary or in the Supplyco subsidiary? A. At the moment, we have included them in the Wiresco cost to be consistent with a model which has been used in the gas industry. All these rules are presently being reviewed. And if there's a competitive portion in these costs, certainly I think some of these costs will go into the default supply or on the energy services side. At this point in time, all the costs associated with customer service are dealing with the distribution [Questioning] 879 Participants service and they are in there and they may be classified differently in future and we'll see what the rules are at that point in time. Q. I'm glad you brought up the gas industry. There's actually a market design task force within the natural gas industry that they're looking at this particular issue, where you put your billing costs in your actual tariff. They're suggesting -- I know the model right now that's actually working has a billing cost in the distribution side, but they're actually suggesting pulling that out and having that as a competitive business so that a retailer can actually provide the billing service themselves as opposed to the distributor providing that billing service. Based on that and when we come into competition, would it not make some sense to put those costs into the Supplyco, or actually into the administrative adder on top of the default supply; is that a possibility? A. Well, a distribution company will always have a need for, you know, services like, or activities like customer care, the call centres and billing for the distribution portion of it. But if a different ruling comes out from the Board and other things develop from a market perspective, sure, that is a possibility and I think other jurisdictions are also looking into that. Q. Okay. My next question is on page 14. Your asset condition restoration, the theme that sort of came out of the transmission group was there was, [Questioning] 880 Participants it's sort of been talked about today, but it hasn't really come up on the table, is that we're in a -- the transmission group was very up-front and indicated that we're sort of in a catch-up mode. Is this the same; would you say that's the same in the distribution side? A. I'm not sure I would classify it as a catch-up mode. We have pulled out this line from an understanding point of view, a separate line called asset condition restorations. Certain assets are restored as part of the facilities line which is lines and stations because the assets are also restored. In 1997 when we did specific asset condition assessments, three specific programs came out of that and those were classified in there. As I mentioned before, like one of the programs in this one is the poles program, a replacement of poles, and this program calls for replacement of 10,600 poles, but we will be replacing about 23,000 poles in total as a result of this capital program. So there are some replacement programs in there and the purpose of highlighting this really was that these programs resulted as specifically when we did the condition of the assets. So in previous years, asset condition assessments were not done in a very organized manner. The utility managers were relying on their knowledge of the condition of the assets as opposed to doing some proper asset condition assessment and ... so I'm not sure whether we [Questioning] 881 Participants can classify that as "catch-up work" because we did not have the benefit of these proper assessments which were done at the end of 1997. Q. How long have we known the poles have been in bad condition? A. As I mentioned, the utility managers certainly will look at the condition of -- look at the poles and they would go with the knowledge of which poles need to be replaced in what particular area. Maybe I can turn over to John Rogers who has been a utility manager in the past and he can maybe speak to that a little bit more. MR. ROGERS: A. When we, in the Utilities back between '93 and '97, looked at the conditions of the poles and the like, we had a knowledge based on we had work centres that reported to us and we worked with, crews that were in the field who we worked directly with. We had a pretty good handle on what areas where we had customer interruptions, customer outages. Based on local knowledge and some anecdotal type information, what we did is, we had capital funding limits that we had and we put money across the different programs based on priorities such as the effect on the customers, customer demand and everything else. Were we aware that there were poles that were in difficult condition? Yes, and we had programs that were dealing with them. Would we have liked to have dealt with more? [Questioning] 882 Participants Yes, we undoubtedly would have at the time. Q. Okay. On page 15 we talk about the SCADA and the DOMCAMS programs. And my reading of the application as well is that these programs will do various things, one of which will be improve losses? MR. URBAN: A. Yes, I can speak to that. One of the problems with losses is that although you may know what your total losses are, to be able to go in and reduce losses, you have to identify specifically what is causing the losses and then, of course, find the cost optimal way of reducing the losses. So our losses are distributed all over the system and they depend on things like loading on assets, the size of the wire, the balancing of the load between the various wires and so on. At the moment, we have no good information on the flow of electricity through the individual assets, so particularly SCADA, which will bring us back load information and then integrate it and superimpose it on the electronic model within DOMCAMS, will give us a much better sense of where the loading is and allow us to target the improvements. Q. So let me understand that. This capital will not essentially reduce losses. It will give you the information in order to find out where the losses are a problem? A. That's correct, yes. Q. So that's why actually your losses are the [Questioning] 883 Participants same in both years in your revenue requirement? A. On an ongoing basis, we reduce losses, but on an ongoing basis, the system losses also change on their own depending on the loading on individual assets. So the focus, though, is to control what we can control and improve what we can improve. Generally speaking, what we would do, is look at investments that are being made for other purposes, make sure we capture whatever loss reductions we can in that process and reduce losses on an ongoing basis. What SCADA and DOMCAMS does for us is it gives us a kind of a new opportunity to see what's happening, to make operational configuration changes and to balance loading better and more proactively and reactively. So in part, it's just the information. In part the asset management system piece of DOMCAMS will provide tools to allow a better study, but of course, the SCADA and the DOMCAMS don't reduce the losses. It's -- Q. It's just in their initial tools? A. Yes. Q. So, I guess from that we can't really expect losses to decrease over the interim period. Most likely they would decrease after 2000? A. Yes, yes. Q. Page 16 and 17 -- and I don't want to talk about the numbers. I want to talk about the LV business. The LV business is another business which the distribution company is responsible for and I think you [Questioning] 884 Participants mentioned -- you referred to it in your presentation, that you also serve 202 municipal utilities. I guess my question relates to, why are you not coming forward with a revenue requirement and -- well, specifically a revenue requirement, and to maybe follow the example of your transmission colleagues, a tariff for the sub transmission or the LV business? MR. SURI: A. The distinction we have made on LV and rural is really dealing with different voltage levels or from feeders which are coming from a transformer station going to a distribution station and the secondary side from a distribution to a pole-top transformer. The combination of LV and rural is the total distribution here. The municipal electric utilities could be fed from the secondary side of the distribution station also. So really, it's all one distribution system. And we talk about, because we have distributing stations in there and there are feeds going from the distribution system, we have separated it and there are different classes of assets in there. At the DSs you have station transformers as opposed to distribution transformers or service transformers on the poles, but it is all one business, and that's the way we are treating it. We're not treating it as two separate businesses. Q. So does that mean down the road that the MEUs would pay the same distribution toll as a rural customer? A. No. What we are going through right now is, we are going through this unbundling of the whole -- [Questioning] 885 Participants essentially the cost, the transmission, generation and distribution. Municipal utilities are not going to be paying transmission and a distribution toll, but this is unbundling of the costs and we're going to look into that. Q. So in the next application, you'd come forward with a charge for this particular business to the MEUs? A. Okay. I'm not familiar right now what we are going to do in the next application because now we're into rate-making and those details and certainly -- you know, I think other panels may have answered that, we'll look into that. I'm not up on the rate-making case. Q. And last question, page 29. MR. HARDY: Sorry, before we move on, I just wanted to clarify the last response. I heard that you weren't clear what's going to be coming forward, but that you would also look into it. So are we expecting some additional - we have, I believe, only one panel coming after this. Are we expecting some additional information coming forward or that's something in the future that you...? MR. SURI: I think that will be something in the future. MR. HARDY: Thank you. MR. BACON: Q. I think this one is fairly simple, it's on your cost of distribution measure. It does say it's under development, so I recognize that. The first one, it's under cost distribution, OM&A [Questioning] 886 Participants plus cap, CAPEX, over megawatthours/kilometres, is that -- where did that ratio come from? Is that something that you developed on your own or is that something that is an industry standard? MR. SURI: A. I think my understanding is from the people who are helping us with development of the measures, that this is the ratio which is being used in the industry and many of the utilities who are looking at the cost of transport or cost of distribution are looking into that and OM&A and capital have been added because many utilities have different accounting practices for charging something to OM&A and capital. This is really saying, is that putting the data, you can compare it. So the answer is, yes, it's being used in the other utilities. Q. It's not really something that a customer could relate to in his particular rates because most likely you'd be taking OM&A, plus your fixed costs, your depreciation and interest and potentially income and dividing it by the same number to really get a handle on what the cost distribution is to the customer? A. That's correct. Q. Okay. A. I think the customers will see what the rates are going to be as a result of all these things, but these are the measures which would be used within the Services Company or by the Energy Board and so on. MR. BACON: Okay, thank you. [Questioning] 887 Participants MR. HARDY: Okay, why don't we continue with questions of... And, Richard, I see you're prepared. MR. STEPHENSON: Yes. Good morning, Richard Stephenson for the Power Workers. Q. One of the items that I just wanted to understand a little more about was the status of your computer and information systems and billing systems. In the period after market opening, and I appreciate some of this has not been fully resolved yet by any means, end-use customers are going to receive either a single bill with unbundled components or multiple bills of some kind. One of the entities that's going to be providing bills, to just use your retail customers as an example, is SERVCO. You are going to be directly billing your customers. Assuming that we're in a situation where receiving a single bill that contains unbundled components, do you have in place computer information systems, billing systems that are capable of dealing with that; and if not, are you putting them in place? MR. SURI: A. We are putting the modifications to the system in place to take care of that particular situation which would deal with the situation you have described. Q. And is that reflected in your capital program or is that somewhere -- is that not a capital item? A. That is reflected in the capital program as [Questioning] 888 Participants part of customer care capital. Q. Okay. Another item: I attended a workshop dealing with consumer information. This was dealing with items, for example, like labelling of energy, reflecting, for example, the source of the generation and so forth. Are you familiar with that concept as it applies on customer bills? A. I'm not entirely familiar with that. Q. In any event, the OEB is conducting workshops on this issue about what customer bills will contain and one of the proposals is that bills will contain environmental information, for example, saying that, you know, this is wind power, whatever, that kind of thing, in order to facilitate customer choice in the development of the marketplace. Are your billing and information systems capable of providing that kind of information; and if they aren't, what are you doing about putting that in place and have you funded it? A. I'm not familiar with all the specifics of the modifications which are being made to the customer care system, but my understanding is that we are making changes to the systems at this point in time that it could handle the multi-supply, multi-energy supply environment, and also dealing with the issue of security and fire walls between that and... but I'm not familiar with whether it's handling some of the other items or not. Q. Just to keep the jargon comprehensible, when [Questioning] 889 Participants you are talking about fire walls, are you talking now about issues about -- also, are you talking about the same thing as ring fencing in the sense of to avoid -- to clarify where costs are and -- A. Yeah, it's the issue of dealing with security of information, that the people who need to know information, they are the only ones who know the information. Q. Let me turn to another subject and that is, you can turn to either page 17 or -- it's really the conductors, the poles and the transformers and your reflection of the vintaging of your asset base in these items. I may be wrong, but in terms of the -- in the anticipated number of replacements that you are forecasting in '99 and 2000, it doesn't -- it seems like the number you are forecasting to replace is not sufficient to even maintain the average vintage of your -- of these various components. Your median age is going to get older not younger by virtue of your planned replacements; am I right about that? A. In general, I think we are attempting to design programs that will maintain that whatever old poles we are adding to the population and making the median the same. One of the things that I mentioned before is that there is an uncertainty at this point in time that where [Questioning] 890 Participants these poles are, how many we will -- actually will go and find them. The program really says is that if you are going to be replacing all penta-poles in sensitive locations it's an estimate that we have included, and when we actually go and find out we may have some higher number. But in a general sense I think we were trying -- my understanding from the poles was that if we were going to be adding another 24,000 poles who will be reaching their expected life next year, we are trying to replace 23,000, 24,000, in that range, so we're not falling behind there. The asset conditions assessments which were conducted in 1997, it is not a one-time exercise. It is an exercise which is currently continuing and we are actually because knowing -- because age is only a starting point. It is the actual condition of the assets. So that's the variable there. Q. I appreciate that. Is it possible -- I don't know if you can even derive it from these charts or if it's something that's independently available, but another measure would be a median age figure for each of the poles and conductors and transformers. Is that information available in terms of both it's current and historical and projected? A. It certainly can be calculated. I have not looked at it. John, maybe.... MR. ROGERS: A. Yes, the average age of the [Questioning] 891 Participants poles is known. Q. Both on a historical, current and projected? A. We know through our asset accounting the number of poles that are in given years and what the average age is. With regard to the programs, the program for 1999 will remove approximately something around 24,000 poles from the system. The number of poles that are exceeding 35 years during the same year is about the same. So it's roughly a balance. The specific age of the poles that we take out is not known because the specific poles will be identified through infield examination of the plant. Q. What about conductors and transformers? A. With regard... Q. The same question, the average age or median age in terms of the -- A. Yes. Yes, the average age of transformers and the average age of conductors is known as well. Q. I understand that, but the question is, the real question is what is the effect of your replacement program on that? A. The replacement program around conductor, there's programs around No. 6 copper; No. 4, ACSR. Those conductors were put in the place back in the 40's, 50's. So the age of -- they would be around the 50-year mark or 55-year mark sort of thing that's coming out for those two. [Questioning] 892 Participants The intent would be to take a look at the older conductors, do visual inspections and determine which are the ones that are the most important to do. As well as taking a look at the number of customers that are fed off each line. It's a balancing act between the age of the conductor, the shape of the conductor and the impact of having an outage. Q. I heard all of that. My question, however, was -- MR. HARDY: I think we are having some difficulty having -- MR. STEPHENSON: Q. Do you have a prediction as to the average age of your conductors after you've done your '99 and 2000 replacement program? MR. HARDY: I'm hearing the question. I'm not sure if I am getting a response from the panel that's consistent with what Richard is asking here. I sense you're asking for something graphed or something that - MR. STEPHENSON: No. Q. I mean, at the moment the question is: Do you have a prediction. That's a yes or a no question, and then if the answer is -- MR. ROGERS: A. No. Q. You don't? A. No. Q. Okay, and what about for transformers? Do [Questioning] 893 Participants you have a prediction as to the -- in terms of the effect on the average age that your replacement program will have? A. No. Q. I heard that by virtue -- that the anticipation is in the years after 2000 your capital cost for your sustaining capital is anticipated to decline? MR. SURI: A. That's correct. Q. And at least part of that is due to an anticipation in decrease in unit costs, I guess, in efficiencies and so forth? A. That's correct. Q. In terms of the level of work, for example, the number of poles, the number of kilometres, of conductor and the number of transformers that are being replaced, is that anticipated to increase, decrease or maintain the same level? A. I don't have the details here, but the general understanding is that either it will remain the same level or increase. Many of the replacement programs are five-year programs. So we are looking at replacement of a specific component over five years. So the concept would be is the unit cost will drop and we will maintain the rate at which the replacements are being planned and it would be either at the same level or it may increase also. Q. You were asked earlier some questions which [Questioning] 894 Participants reflected on the rather marked decline in the number of installations in the years around '94 through '96 -- '94 and after of both -- of poles, conductor and transformers and we did have an explanation of that. My recollection, and perhaps you can confirm this for me, is that in the 1994 period and beyond there was, as a result of the Ontario Hydro restructuring which took place at that time, a massive reduction in capital programs across the corporation and that the distribution system was not excluded from that reduction; isn't that right? A. That is correct. Q. And that the reduction in these installations is at least in part due to -- that the mandated decreases in the capital program that took place at that time? A. I would not use the words "that they were mandated". Yes, the capital programs were -- the total envelopes were reduced across the Board because we had other competing priorities in the corporation, but asset condition and the way we are looking at the assets -- the condition of the assets, those were not even looked at in an organized manner. So to say that those programs were basically not approved, my feeling is probably in many cases those programs were not even proposed. Q. Sorry. You misunderstand. I'm not suggesting it was mandated that those programs were cut, [Questioning] 895 Participants but you did get a mandated reduction in your capital envelope at that time? A. That is correct. Q. And that flowed down as a matter of fact into reduced installations during that period? A. Again, it would depend on the capital category you're looking at. I cannot recall any instance where any utility manager did not have enough capital to take care of all their demand capital or take care of the situations which were really causing a lot of grief as a result of interruptions to the power supply. But utility managers did not have organized replacement programs and so that really was the situation. Q. Just -- this kind of replacement program, I asked this question of the transmission people and I think they agreed to it, that in terms of the condition of these assets and replacement of these assets, these are -- there is a cumulative effect of either retention or neglect, that will not necessarily be revealed in the next year, but that these cumulative effects take place over time before they may ultimately revealed; is that fair? A. You're correct there is a tradeoff between the maintenance and the replacement of the assets, and certainly one of the things we are looking at is trying to gain more information about these assets. Q. In terms of the management of your business as essentially the provider of this common carrier, I take it that -- I think you said this maybe in slightly [Questioning] 896 Participants different form earlier on, that long-term cost minimization in terms of the maintenance of your assets base is a governing principle for your organization? A. That's correct. Minimizing the long-term cost of these assets. MR. HARDY: Richard, it's -- MR. STEPHENSON: That's fine for now. MR. HARDY: Okay. We will come back later on this afternoon. I have 12:05. So I suggest we break now for lunch and come back at 1:05. I'd like to start after lunch with back to the panel or the Board -- or the Consultants and then we'll move back to participants. Okay. We're adjourned until 1:05. ---Luncheon recess at 12:05 p.m. ---On resuming at 1:10 p.m. MR. HARDY: Why don't we resume? Now, just in terms of procedure, I've been informed by Board Staff that they would prefer to have a continuation of participants' comments for a period of this afternoon in any case, so we'll probably resume with participants' comments. Before we do, I just wondered, from this panel, is there anything you wish to add or contribute from this morning as a start-off? MR. SURI: Not at this time. MR. HARDY: Okay. Thank you. Then why don't we resume with participant [Questioning] 897 Participants comments and questions? Go ahead. Please introduce yourself. MR. FISHER: Good afternoon. My name is James Fisher. I'm appearing on behalf of AMPCO. Q. On page 184 - that's in appendix 4 - at line 21, it says: 'PBR should be implemented as soon as possible.' And then on page 41, line 3, it says: 'The company is aware of concerns about symmetrical application of regulation across distribution companies in Ontario which make it impractical to move towards PBR.' I was just wondering how you could reconcile those two statements first off and then I was just wondering about what is meant by 'symmetrical application'? MR. SURI: A. My understanding is that Services Company, Ontario Hydro Services Company preference was that we go with PBR at this point in time. The indications which were given to us from the Board were, because we were not the only distributor in the province, there are municipal electrical utilities also who are not ready, so we should be introducing PBR at the same time for all distributors. Q. And what is meant by 'symmetrical application'; is that what you're referring to then? A. That's correct. Q. And what are the -- it says 'the company is [Questioning] 898 Participants aware of concerns about symmetrical application'. What are these concerns? A. It's municipal electric utilities are just not ready to be regulated through a performance-based regulation and that's the only thing I'm aware of. Q. Okay. On page 43, table 6.1, it shows the proposed revenue requirements for 1999 and 2000. Were these approved by SERVCO's board of directors? A. Susan, do you want to answer that? MS. FRANK: A. We'll talk more about revenue requirement tomorrow when actually there will be a presentation on it, but this material was reviewed by the senior management of Ontario Hydro and has very recently been reviewed by the Ontario Hydro board and the OHSC board, but senior management had all reviewed and endorsed it before it was filed. Q. And then the SERVCO board after the fact then? A. Yes. Q. And did they have any comments? A. They've approved the information subject to the OEB's direction in terms of revenue requirement. Q. And did they have any comments in their approving it? A. I think you'll need to be more specific. I don't .... Q. On page 53 at line 8, I was just wondering, [Questioning] 899 Participants why did the past levels of investment and sustaining the distribution structure lead to the decline in customer service levels and backlog of condition-related issues? MR. SURI: A. I'm just trying to look for that line. Line 8? MR. HARDY: Yes, page 53, line 8. It actually flows over to line 9 as well. MR. SURI: I think as we talked about it this morning, the number of factors were there in previous years. One was the different priorities of Ontario Hydro. And secondly, the demand capital had the fluctuations over the years which resulted in different investment levels in the past years. And the customer service levels, it's an indication that we are getting right now is, if you measure by the number of outages and trouble calls which we are getting which were an indication for us that certainly the outage calls were on the rise and that's the only inference we can draw at this point in time. And as we indicated, that we are going back and looking at the actual condition of these assets and an asset condition assessment was done back in 1997. MR. FISHER: Q. And do you have any data on those increasing outage calls which you could supply us with? MR. SURI: A. We do keep track of a number of calls which we receive and certainly I can -- I don't have [Questioning] 900 Participants that in front of me here and certainly I can consider looking at it, what's available. MR. HARDY: Okay, I'll make a note of that then. MR. FISHER: Okay. Q. I guess just to follow up, I was just wondering, why should customers in 1999 and beyond pay for the management decisions which led to these declines in customer service and backlog-related issues? MR. SURI: A. The assets which are really there at this point in time -- like I said, some of the programs which were developed -- or the condition of the assets started in 1997 and after that we started developing these asset restoration programs and -- the word 'backlog' really indicates that the level of replacements which have been done in previous years is not to the level which we may have done in early '90s or early '80s or late '80s and -- I'm not sure from a customer's perspective because we are carrying out the work at this particular point in time and really, that's where the cost needs to be allocated. Q. On page 63, line 13, relating to the replacement of an estimated 50,000 pre-1979 vintage contaminated transformers, you know, it's been known for a long time that PCBs are toxic and harmful to human health and the environment. I was just wondering, why has it taken so long to replace these, 20 years? A. That number 50,000 should be 13,000. There was a correction on that. [Questioning] 901 Participants Q. Uh-huh. A. And we have been looking at the PCB contaminations, contaminated transformers, and some replacements have taken place in the past and certainly at this point in time -- it, again, goes back to how these things were managed in the past. Again, we have started looking at these things on a provincial basis at this particular point in time. When the asset management group was formed, the whole focus there was to start looking at the condition of assets, start making decisions about the programs as opposed to be some of the decisions which were left to individual utility managers who were making these decisions. These programs are appearing as a result of us trying to look at provincial priorities and us trying to look at what the roles and responsibilities are for the services company from a stewardship perspective. So the PCBs were -- you know, I think the rules and regulations have been in place and efforts were made in the past to replace transformers. And at this time what we are recommending is, that we should be looking at it and the strategy, as I discussed it, really was that we want to probably focus on some of these things and trying to eliminate these PCB contaminated transformers over a period of the next five to eight years. Q. I guess, you know, my point being, you know, it's been known for a long time the hazards associated [Questioning] 902 Participants with PCBs. You would think that would gain a higher priority decision in order to deal with these as expeditiously as possible. A. I think utility managers and looking at what has been done in the past, everybody was told what was required within the regulations and legislation. Essentially all the environmental management systems were in place within every utility. The question really comes to how aggressive you are in elimination of certain things, how aggressive you are in treating the land contamination issues because there's no regulation required around that and those are the initiatives the company can take on its own to take care of your stewardship responsibility. Q. It just seems a little surprising to me how, you know, in, say, in the last ten annual reports of Ontario Hydro there's always reference made to their high level of due diligence with respect to environmental stewardship and that -- things like this and contaminated lands have not been ongoing programs. MR. HARDY: It seems like -- again, I think I'm -- I'm not sure if the panel wishes to respond and once again, I think I'm hearing that question a couple of times now. MR. FISHER: Those are my questions, thank you. MR. HARDY: Do other people wish to provide questions? Ken? [Questioning] 903 Participants MR. SNELSON: Yes, I have a few questions. It's Ken Snelson representing AMPCO. Q. I don't think, Susan, you'd be happy if I didn't have a question relative to the 1998 business plan. Having explored that somewhat with the first panel, we have determined, I believe, that overall the capital program for 1999 that is in this submission is considerably higher than the capital program that was part of the 1998 business plan approved about a year ago and I'm wondering if you can look at table 8-6 on page 52 and whether you're able to run down the 1999 column and tell us what are the equivalent numbers that would have been included in the 1998 business plan for 1999. MS. FRANK: A. The 1998 business plan with the 1999 number in it that you brought - actually, I believe it was on day 1 of these technical conferences - was a services company integrated number that you had. Q. Yes. A. And we didn't at that time have a separate set of numbers for what is now the distribution and transmission system. The company wasn't organized in that fashion at the time that we prepared those numbers, so I do not have an equivalent set of numbers from last year's planning exercise for each of these. I can give you the last year 1998 numbers for what we were planning to spend in '98 but not last year's business planning exercise comparable 1999 projections. I just don't have it by distribution. [Questioning] 904 Participants Q. Okay. Do you have it as regards to the total? A. The total was the piece that you brought to our attention the other day. Q. That was the total for transmission and distribution together. A. And that's all we have. Q. That's all you have? A. Yes. Q. Okay. Is there -- if we can't have the numbers, is there a sort of a narrative kind of description that you can give us the essence of whether the numbers are -- generally the programs are higher than planned a year ago? I presume that they must be to contribute to a higher capital program. And what are the causes for that? A. I'm only going to start because I really believe this is Vipin's question to question to answer, but there were items when we were preparing the business plan in 1998 that were outside of our range of awareness and items such as the asset condition assessment was not at a stage of development that we incorporated it in last year's planning exercise. So any of the numbers that we had for the services company did not include any asset restoration capital. It just wasn't in there. We didn't include it at that time. We were not comfortable including it. I think from my perspective, that's the biggest [Questioning] 905 Participants factor that would mean that the capital expending that we're projecting for 1999 would be higher today than it would have been a year ago, but I think it's appropriately Vipin's question. MR. SURI: A. The only other item I can add is, is the operations capital, like the DOMCAMS and SCADA, were the programs that probably were not included at that -- forecast at that point in time. Q. But you had at that time already decided to go to an asset management model as I believe. A. That is correct, and on the distribution side, if you go back to the structure of Ontario Hydro at that time, we had a retail company and we had a transmission company. Back in the middle of 1997, decision was made to go to the asset management model on the retail -- in the retail company. And certainly at that point in time, all those decisions about DOMCAMS and SCADA and so on were not there and those programs were not prepared at that time. This business plan which you're referring to was published in February of 1998, effective organization which came into -- which is today, if my recollection is right, came into effect sometime first of December in 1997, so it's shortly a few months after this plan was published. Q. Okay. Now, you did mention just then that at that time, you were organized into a retail company and a transmission company? [Questioning] 906 Participants A. That is correct. Q. I presume that the retail company would have had its capital plan at that time? MS. FRANK: A. At that time we had no plans approved other than at the Services Company level. There was -- we had bundled everything together into a services company and that's the only approved plan we would have had and anything that would have gotten any review. Q. Okay. A. Can I add one other item just so -- because we really missed it, another change? Q. Sure. A. And that's the distribution support one. I should have mentioned that earlier. Obviously a year ago when we did the planning, we didn't realize we were going to break this company apart. Certainly not in this kind of time frame did we realize we were going to break it apart. So some of the distribution capital which is the pay system cloning and -- some of that work was not -- would not have been considered as part of the services company a year ago. Q. Okay. Coming now to sort of the reorganization, one of the things that concerns me is sort of whether or not it makes sense to reorganize a distribution company that's covering a vast area from the Manitoba border to the Quebec border and whether it makes sense to centralize that into one central sort of decision-making and operating organization. [Questioning] 907 Participants I believe that in Vipin's presentation this morning, he talked about the situation about 1993 when you had 15 utilities and about ten years ago, that seemed to be the vogue of management, that you wanted to decentralize management. You wanted to empower local managers to make decisions in their own areas and give them the authority and the responsibility and the accountability to manage their business in the best way that they saw fit. I'm just wondering if you could comment as to whether or not the 15 utility organization in 1993 was a reflection of a sort of a decentralized management philosophy. MR. SURI: A. I think we need to probably even go way before that. Ontario Hydro was, as you're quite aware of it, was organized into different regions. The regions had distribution and transmission into -- all part of individual regions. In 1993 when there was a restructuring done, at that point in time it was felt that a regional structure really was resulting into different kinds of standards being used, even distribution and transmission side on the system. It's one system, but it was being run as different systems. From there, the structure came up was that we have the utility -- we separated the transmission and distribution at that particular point in time. Distribution was into retail utilities, transmission was into transmission districts. [Questioning] 908 Participants The evolution of that took place was that we need to start planning and that's the point in time and we are looking at the asset management model, that what functions need to be done on central basis and what functions really need to be in the field. Obviously, the field offices need to be close to where the customers are if we were to meet our service standards. The concept then came that if it's one system we really need to start looking at planning of the system, design of the system, standards, what material needs to be used all on a provincial basis. In addition to that, the key was that the priorities of the programs and the dollar spending really needs to be done on a provincial basis. In the past, certainly, yes, it may be the philosophy, yes, that we were decentralized, that there was a model there that even in the whole corporation at that time we did not have the asset management model and we were getting into decentralized decision making. Certainly when we were aware of the asset management model which was introduced in utilities in U.K., New Zealand and Australia, and the company in total started looking at it and looking at the benefits of the model which said that the results or decisions which were made in 1993 really needs to be changed so that we can gain all the efficiencies. Q. Okay. I think it's -- you will agree with me [Questioning] 909 Participants probably that it's fair to say that the asset management model, the DOMCAMS system and the SCADA system, which we are currently now reorganizing to implement and we are investing in them, this is to move towards a more centralized style of management? A. More centralized decision making. Asset management model talks about decision making at the asset manager level. The execution of work still takes place in the field. And the words "centralize" and "decentralize" imply a lot of different things to different people. If we are talking about decision making, the answer is yes, it is more centralized decision making. Q. What it seems to me is that the management philosophy seems to go in cycles. We decentralize one period and then we sort of recentralize at another period. My question is: How much of the cost of the DOMCAMS system and the SCADA system will become redundant when we start to decentralize again in another five or ten years time? A. Like I said, I think the management philosophy of centralization and decentralization, definitely there are different views about that. I personally don't think this is centralization in the traditional sense as we call it centralization. Asset management model is -- it's a centralization of the decision making. It is not centralization of everything. [Questioning] 910 Participants It also talks about synergies of the work forces and the concept being as a manager when you are in the field you are managing your assets and your people. My position as distribution and work asset manager really deals with management of assets and performance of those assets. Management of people is done by the network services organization. And we still have decentralized operations centres in the field. So I'm not sure whether we can just put a level on it that this was really a recentralization. And from what we are looking at this is one distribution system in the province. I really cannot see us going back to looking at saying that now we're going to manage the system in a manner that we should have different standards, different service levels. We're one customers -- similar customers and to have different standards how we are operating I really don't think we are probably going back to that. Myles, do you want to add something to that? MR. D'ARCEY: A. Yes, if I could just add to the comment whether this would be a sunk cost to centralized operation, access, up to date, current information on your assets is vital whether you are centralized or decentralized. I think if you look at the municipal utilities there is a realization in the decentralized model that they have that they have implemented SCADA systems to do [Questioning] 911 Participants just that, to have up to date, real time information on their assets. Q. Over much smaller areas, much more contained systems? So they are operating over a much more contained system which isn't spread over a huge geographical area? A. Agreed. I don't debate that, but the principle is the same. It's access to the data so that you can manage the system. Q. Okay. Coming back to the SCADA system, is there going to be one SCADA system for the province with one control centre or is it a regional -- question of regional systems? MR. SURI: Doug, do you want to answer that? MR. URBAN: A. Basically the SCADA project is the installation of a box of each of about 940 distribution stations. Where the information is communicated to will be our operation centre and that informational feed into the asset management system and blend with all of the other asset information, all of the electrical characteristics, the models, the connected customers, the outage information, et cetera. So basically the answer is yes. Q. It is one operation centre that it is coming back to? A. One operational centre, yes. Q. Do the DOMCAMS and SCADA systems have additional capacity built into them to handle additional [Questioning] 912 Participants lines, additional customers and so on? A. Yes. The SCADA, of course, would require additional field wiring devices. Q. I'm talking really about the central receiving system. A. Yes, I would say so. Q. Now, we heard from Rod Taylor that OHSC is actively interested in taking an active role in distribution system reorganization, including opportunities where OHSC might possibly acquire municipal utilities. And my question is: How much of the DOMCAMS and SCADA system costs is attributable to providing extra capability to provide for future acquisitions? A. I would say probably none. The basic backbone of owning the rights to the software would be common. But in terms of the costs that you see in the submission, most of them are related to either data conversion for existing systems, for acquiring new data, that's on the OM&A side, installing RTUs and communications. RTUs are field devices for SCADA to our centre. So most of those costs are, say, they're -- virtually all of those costs are attributable to our existing asset base, but the question of could that piece of software and could that centre handle more customers? The answer is probably yes. [Questioning] 913 Participants Q. Okay. Now, just move on to a different area and probably a very simple question. If you look at page 24 -- MR. HARDY: You have to help me out on that one. MR. SNELSON: Okay. Yes. Q. I'm having difficulty too because my page 24 doesn't exist. Actually, it's page 18, line 24. It says: 'This two-year application is submitted in the context of the government's rate freeze policy which will continue until the end of the year 2000.' And this may be -- this is a question I could have asked any of the panels, but it is something that's puzzling me, is what does a rate freeze mean in the year 2000 after the energy market is opened? MS. FRANK: A. This likely should have read: "...until the end of the year 2000 or the opening of the market, whichever comes sooner." Indeed we do intend to come back with the proposal on the distribution system that will be appropriate for the period after the market opens. So it was likely not adequate care in the way we phrased that. Q. Okay. And I had some questions on low-voltage lines, but I think they've been dealt with this morning. I have a question on line losses on page 120. I hope I have the right page number this time. [Questioning] 914 Participants Around lines 11 to 14 it says that line losses are based upon an engineering calculation and if the amount of energy you buy is metered and the amount of energy you sell is metered, then isn't the losses the differences between the two amounts and in that case why would you need an engineering calculation? MR. URBAN: A. We incur losses for our own 960,000 customers and we also incur losses attributable to service to direct customers and municipal utilities. So right off the issue becomes a little more complex because we need to allocate the losses. As far as what was done, the engineering study took place I think it was over a five-year period. It actually did measure energy in, energy out. Of course it required a long-term study because, as you're aware, the billing cycles, the metering cycles on the consumer side vary considerably, even in some cases annually on seasonal customers. So it took a fairly lengthy period to establish this baseline number. That's what this refers to. Q. So this 8 per cent distribution line losses is the losses attributable to the Ontario Hydro retail customers, the losses attributable to direct customers fed from 44 kV lines or from municipal utilities. I'm sure it would be a different number because they don't use the same infrastructure but this isn't an average of the -- of all of your customers, it is just the retail customers that incur the 8 per cent loss? [Questioning] 915 Participants A. That's correct. Q. Under tab K of the supplementary materials, there is some information on trends in electric energy and peak demand. And if you look at page 6, there is a Table 2.0, and the column that says "retail" I believe is the retail load supplied from your distribution system; is that correct? A. I believe so, yes. Q. And you have mentioned that the rate of growth of your load has slowed down substantially and I note that you achieved a total energy sales of 19.9 terrawatthours in 1998 and you are forecasting a decline to 17.9 terrawatthours in the year 2000? A. I'm just reading yhe figures the same as you are, yes. Q. I'm presuming the figures are correct, they are in your submission. The question is: If you would like to comment on the need for development capital to a system which is basically experiencing a decrease in load rather than an increase in load. A. Sure. Development capital, could you be specific? You are after -- Q. Well, I think it is a question of the trend and I understand that you will have some areas where there are new customers connecting even if other customers are going down in load? [Questioning] 916 Participants A. Exactly. Q. And you will still have some need for capital for providing for those changes? A. Yes, that's correct. Q. I just wanted you to comment on the trend and the level of capital that was being involved? A. Right. What we're seeing -- what drives development capital isn't energy. It's peak demand. Now, that's a fine distinction, of course, but the other thing that I guess is most important to remember is that the capacity that we were providing to supply new customers under -- or new load under these programs is because there is a gap between our ability to serve in some local area and the demand in some local area. So if we looked across our system we have 2,300 feeders. Those feeders are broken into little sections. We probably have some number of thousands of local supply areas, any of which could be experiencing an overload or growth and a gap in the capacity. Even in an area where the total load is declining, what would substantiate that kind of thing, if we look at the patterns of our new customer connections they tend to be around major cities. So we have Ottawa, Kingston, Toronto, Windsor and so on. So there is new activity, there's new load in local areas. If we look at the provincial load growth, on the other hand, southwestern Ontario around Metro Toronto, Golden Horseshoe all tend to be high load growth areas. [Questioning] 917 Participants If you go east from there, we've even got negative growth. So you're quite right in that the activity is driven by new connections as well as growth. Q. Okay. And there was a comment made this morning - this is on a different area - about the transfer of the assets to SERVCO and that there was some questioning about what if the assets are of questionable value. I think we have heard that there have been provisions made for restoring -- by the previous Ontario Hydro organization for restoring the assets to an adequate state, and it just seems to me that that's an indication that maybe some of the assets do actually have questionable value. MS. FRANK: A. Actually, I don't agree with your assumption, Ken. I think that -- there are a few comments you made that I want to go back and maybe change slightly. The assessment that was done identified indeed that the condition of some assets needed attention, and you said a provision was made by the previous Ontario Hydro and there was no provision made to do any capital restoration. So I just want to make sure the record is clear on that. Q. Okay. Yes. A. The only provision related to OM&A expeditures. No capital. Q. I realize that. A. Okay. So now when you are saying, therefore, [Questioning] 918 Participants are they of questionable value? The value that we have in these assets is their net present value. Often these assets are, particularly the pieces that are 55 years of age and older that we were talking about this morning, will be fully depreciated. So according to our books they have no book value left. They are fully depreciated. So to say that that asset which we now find needs to be replaced is overstated on our books. Obviously not the case because it doesn't have a value. If -- I think your question has to be, are you applying the right depreciation policy? Is that the question? Q. Well, you know, I am really just raising the issue of the provisions again. I think I understand what has actually happened, right. But just in a commonsense kind of way, as a non-accountant, when you make provisions to restore assets to an acceptable condition, then to me it has at least a common sense implication that somehow none of the assets aren't in an acceptable condition at the time that you needed to make that provision. A. But it makes no statement about the value of the assets that you currently hold on your books. Q. It may be different to the accounting question. Those are my questions. MR. HARDY: Thank you. Are there other participants perhaps who have not asked questions at this [Questioning] 919 Participants point who wish to ask questions. Again, the floor is open to everybody in attendance. Go ahead. MR. SCULLY: My name is Peter Scully. I am representing a company called ECNG, which is an independent consultant and manager in the direct purchase energy field. Q. I just want to double back to an area that the Board consultants were touching upon this morning and that was your judgment about how much of your capital expenditure program you can afford. My background is in natural gas regulation and I'm used to seeing in a presentation a section which says: Here are the rates that we propose, here are the volumes or the kilowatts that are going to move, here are the revenues that will be generated. Am I correct that that isn't here in that presentation, in your presentation? You haven't done a projection of revenue based on I guess the existing rates? MR. SURI: A. We are still looking at an allocation of the distribution revenue requirement from a total bundled electricity rate. Those kind of details which you just talked about, we at the moment do not have any performance based regulations at this stage and what we are really defining is what the distribution revenue requirements are. The other fact really is, it's a services company being a company which is less than two months old and [Questioning] 920 Participants we're trying to look at all the data at this particular point in time, but the answer really is, that this is a revenue requirement. Because we are starting this company on April 1st, we need a licence to operate for distribution and we need a rate order. We cannot start operating without the rate order and the funding is really going to come from an allocation of a bundled total retail electricity revenue and all that unbundling will take place when the market opens sometime in year 2000 and that's the point in time. Q. But you've got your 1999 year to deal with and your Year 2000. You know there's going to be a revenue stream. You don't know -- you don't have the total number here and you don't have your allocation of it; is that...? A. The allocation is, there is a distribution revenue requirement. Q. A requirement versus revenue generated. I'm asking you about the revenue that you anticipate will be generated. You know what you need. A. This submission or application is based on a cost of service regulation, so that's the cost and really that's your revenue requirement. Q. Okay. So when -- I was just looking at page 126 of your presentation and at line 13, you have a retail revenue stream. Is that just a forced number? It does happen to exactly match your requirement which makes me a little [Questioning] 921 Participants suspicious. A. Like I said, because this is a cost of service application, so really revenue and cost basically in that scenario are equal and the cost includes the factors which have been shown in there. Q. So would it be fair to say that line 13 is just a plugged number? A. Susan, do you want to answer? MS. FRANK: A. I'd say line 13 falls out of the -- what we're trying to show on this table 17-1 is what the cost of service was that got you the 911 and then we are trying to say, what costs are not covered by the customers but we get payment from other mechanisms? So line 13 really tries to show that we -- it's the subtraction that you see right above that. They're items that we do not collect from our customer, our retail customers - the rural rate assistance, the facility charge, the recoverable work. Those items are not collected and so that the 701 is what is left to be collected from customers. And you've been asking about the rate, but we're under a rate freeze that has a bundled rate. Q. Yes. A. There is no separate distribution rate at this time. What we're trying to do here is to determine what the appropriate cost of service is for distribution and find out what share of that bundled rate should come to distribution. And that's how it will work. It will be [Questioning] 922 Participants all bundled, come into a pool and then the share that the OEB determines is appropriate for us distribution will get. Q. Okay. So you've had a rough look at what the total pot is. It's more than your $701-million. It's -- I don't know what it is, but it's more. There's enough to cover you and the other entity that needs a revenue stream. A. We've actually filed some information on the total bundled cost of energy, the 7.2 cents. I wonder if I can find the tab quickly that gets you there. Yes, tab H, thank you. And that -- and this was filed on December 23rd. That's the piece that would come closest to, I think, helping you with the question you're - you're answering it - in what we've already filed. It shows the 7.2 cents and the portion that's energy and then transmission, distribution and .... Q. I see. I don't have that because I just have the December 7th filing. Okay. MR. HARDY: Okay. Sorry, maybe we can just -- I don't know if there's an extra copy that we can -- I have a copy myself. MR. SCULLY: I'm not sure that I really need to see that. Q. What I was looking for was the ordinary -- I mean, it's a question of -- the usual judgment for a commercial venture is 'I'd like to spend all of these capital amounts, but I have to make sure that I've got [Questioning] 923 Participants enough revenue coming in to cover it'. And in my mind, if you were just plugging in the revenue -- I wasn't clear that you'd done the judgment of 'I'm going to spend $200-million of capital in 1990 and that's going to generate a $20-million revenue requirement in the year 2000. Will my revenue stream be there to cover it?'. And I guess you're saying to me, we've taken a forward look at the pot and it's big enough to be spread to us if we can persuade everybody that we're entitled to that share. That's the degree to which you've tested your capital expenditures against your anticipated revenue flow? MR. SURI: A. Well, you know, I think, as I said, it is -- you know, you look at the total cost of service and the cost of service includes your operating expense, it includes the interest expense on the capital, the depreciation of the assets and so on, and you look at your total cost which really becomes your revenue requirement. In this case, there are other sources for which we get revenue. Like, it's been identified that there's a rural rate assistance, for example, is the revenue. So that's credited from your total cost of service to arrive at your total rate revenue requirement which is the number $701-million. So you really are looking at your cost of service total which includes all your capital expenditures and all [Questioning] 924 Participants your OM&A program, the costs. So they are provided for in the 911-million number. And before you come back to your revenue requirements for retail -- for the rate revenue requirements, then you look at, are there other sources of revenue which the distribution system will get and subtract that from that to arrive at the .... Q. Presuming that your revenue requirement -- or rather, your revenue stream is going to stay constant or maybe climb a bit if the new customer additions yield the right level of return, your overall revenue requirement is dropping from '99 to the Year 2000. Would you expect your rates to be set at a lower level in that year or what -- A. Okay, Susan, you can probably answer that. Just one comment: The revenue is dropping because revenues are based on what your cost of service is. If your cost of service is dropping, revenue is dropping because that's what we do in a cost of service regulation. Q. Okay. Thank you. Those are all my questions. Thanks. MR. HARDY: Thank you. Are there other questions that participants wish to ask? Okay. I think, Mr. Robertson, we'll probably start with you and then move to Roger. MR. ROBERTSON (OCAP): I rather suspect Mr. Scully - perhaps not for the first time - has stolen some [Questioning] 925 Participants of my thunder, but I'll try -- MR. SCULLY: I apologize. MR. ROBERTSON: I'll try and retread and keep out of his way. Q. This is really a clarification question, a system question: As I understand it, Ontario Hydro retail distribution customers are now customers of OHSC itself. They pay bills on a bundled basis as before. The bill looks the same for those distribution customers? MS. FRANK: A. That's correct. Q. Now, when you gather in all this money from people paying these bills, I understand from the evidence that this money will be pooled and will be accessed by all of the successor companies of Ontario Hydro; is that correct? A. That's correct. Q. You go on to say that the bit you get out of the pool will be allocated to your business based on the revenue requirements approved by this Board. A. Correct. Q. Now, I'm interested in how that's actually going to be done. Have you made any sample calculations of -- on the assumption that these rates are approved of what bit of the pool you're going to get? How is that going to be allocated? A. Well, what we'll get is the absolute dollar amount that gets directed to us by the Ontario Energy [Questioning] 926 Participants Board. I don't assume they're going to direct a percentage. I assume they're going to direct an absolute dollar amount. So we'll get -- Q. If the revenue requirement is approved as it is now, that is your snap on the pool? A. Yes. Q. And will that be the same for transmission? A. Yes, it will. Q. Yes. So I can move on from there to say, if, as a speculation, the Board puts the cost of service down and, therefore, the revenue down, that means that you will get less from the pool than you're anticipating? A. That's correct. Q. What happens to that money that you didn't get? A. The rest of the money that's left in the pool will go to the payment of the finance organization, OHFC I guess it's called. Q. We call it Debtco actually. A. Okay. (Laughter) Q. So, in a sense, your loss is their gain? A. Yes, it is. MR. ROBERTSON: Thank you. That's enough for me. Thank you. MR. HARDY: Roger? MR. WHITE: It's Roger White, ECMI again, Energy Cost Management Incorporated. Q. This morning we heard a lot of discussion [Questioning] 927 Participants about performance measures that needed to be put in place to ensure that customers get the kind of service they're entitled to. Mr. Suri, would you say that those measures are important in terms of knowing what standard of service the customers are getting? MR. SURI: A. Yes, from my perspective, they're important. If I'm managing the assets, I definitely would like to know that. Q. If that's the case, then isn't not having those measures in place, doesn't that make putting forward the case for performance-based regulation premature at the very least? A. Again, I had indicated that the measures have been used in different ways within the different utilities and whether they're important from a Board perspective -- from -- like, the management of the distribution system perspective, these measures are important. You need to know what service standards you are delivering, from a customer perspective they're delivering. I'm not sure whether they are important from looking at what the total cost of the operation is because you're really looking at a different set of measures rather than the customer measures. You're looking at more system measures in that case. Q. I won't remind the Board of their duty to protect customers. I'm sure they're well aware of it. I'd like to go back a little bit to the financial [Questioning] 928 Participants records of the corporation. In the interest of speeding things up, maybe we can -- maybe I can summarize something and people can tell me where I'm wrong. It's my understanding that the corporate books in terms of the plant that's in the field stems from a period where costs and asset counts and things were gathered in the region in many cases and in what used to be called the rural operating areas in some cases and then those numbers were gathered together and they became the corporate books for the value of assets by class, by age. Is that substantially correct? MS. FRANK: A. I would have characterized that the financial records were gathered in a chart of accounts so that any work that was done was put against a category of cost. If it had been done, you know, in one region or another region or by head office staff, there's a whole chart of accounts which I believe we have already filed which people would have charged their costs against. So it's not quite the same pooling as you were suggesting, Roger. It wasn't -- we don't have it by region by region by region. We have it by the chart of accounts. Q. So it would surprise you when I said that the inventory pricing that was going on for many of these utilities that were taking on assets from Ontario Hydro's retail system, that they were using regional records and old cost pools of data and plant by account class and by age of class, that that information exists and is being [Questioning] 929 Participants used for pricing the assets that the utilities are taking on? A. Roger, help me. Are you -- I need to know what -- are you talking part of annexations or...? Q. Yes. A. I think actually Myles -- I mean, Vipin has spoken about the annexation and how we come up with the estimate for that pricing, so .... Q. I'm not talking the estimates. I'm talking about the transfer price based on the field inventory. MR. HARDY: I know we talked about -- excuse me. I know -- I'm sensing there's some difference between -- we did get into this area this morning in terms of -- MR. WHITE: This is substantially different and I'll make my point soon. MR. HARDY: Okay, fine. MS. FRANK: Maybe you should go there because, I'm sorry, I don't get the question. MR. WHITE: Q. Some of my clients have had the experience where assets were identified in the field, that when they went to the books of the corporation, the corporation did not have those assets of that particular age and that particular class on the books of the corporation. MS. FRANK: A. Are you saying, have we ever made any errors in our financial systems or is there sometime when a person locates a physical asset and we look in our books to try to find it? We have pooled books and I think [Questioning] 930 Participants I described that this morning, that we have pooled records. We don't have it in the detail asset by asset. At times, even when it comes to removing an asset, we have to remove it from the pool. We can't physically identify it from the financial system the actual asset. The records are not kept to that level of detail. So I think it's certainly possible that there would be a time when there would be an asset that was in the field, that when we went to our financial system we couldn't find the details to confirm it, yes. Q. I'm looking for that table 17 that we were looking at a few minutes ago, 17-1, page 126. I read on the bottom of that table rural rate assistance at $127-million. A. Correct. Q. Is that part of the revenue that would be earned by Disco as part of this application? A. It is -- Q. Or taken by Disco? A. It's certainly part of the way that we believe we will be funding the cost of our programs, and this is -- the rural rate assistance is actually part of regulation that the government is currently reviewing, just exactly how it would work, but our understanding, that they're considering having the Ontario Energy Board determine what the level of the rural rate assistance will be, so it's certainly part of what we need in order to service the assets. [Questioning] 931 Participants Q. So it's part of what determines the rate of return that Disco will earn, part of the revenue that will determine that? A. It's definitely part of the revenue, yes. Q. Okay. Are you familiar with a statement of Kathleen C. McShane? A. I'm not intimately familiar with this. Q. On page 3 of that -- MR. HARDY: Sorry, you're asking the particular panelist if she's familiar with something and she said she's not familiar. MR. WHITE: Okay. Fair enough. I'm sorry. MR. HARDY: Perhaps you'll want to pose the question and give her some opportunity to become familiar with it and answer tomorrow - that seems to be fair - but to pose that question without the panelist being familiar, I think -- MR. WHITE: That's fair enough. I would ask that if you are reviewing the document over night you pay particularl attention to page 3. MS. FRANK: Could you help me further by telling me what your question is? MR. WHITE: I was just told I couldn't ask it. MR. HARDY: We are trying to be informal and not trying to ambush each other here. So even a hint would probably be fine. MR. WHITE: I find it really interesting that she [Questioning] 932 Participants says that the rate of return should be considered exclusive of subsidies. I am wondering what rural rate assistance is considered if not a subsidy. MR. HARDY: Thank you. Susan, is that clear? MR. WHITE: I am not looking for an answer now. MS. FRANK: Okay. MR. HARDY: Is that clear? MS. FRANK: I will make sure I start tomorrow with it. MR. HARDY: Thank you. MR. WHITE: Thank you. MR. HARDY: Sorry. Excuse me for a second. We will start a couple more questions before we break, and I know the Board Consultants have additional questions. Sorry, do you have a question? MR. WHITE: I am fine. Thanks. MR. HARDY: You are fine. Go ahead. MR. BRYAN: My name is Keith Brian and I'm with Union Gas. Q. I was going to save this question for tomorrow, but it is a follow-up on others that were asked by Mr. Robertson and Mr. Scully. So perhaps I'll pose it now. You mentioned a moment ago that the revenue requirement as ordered by this Board will be your revenue available to you in the year. [Questioning] 933 Participants But I think it's also clear that the revenue pool itself will be higher than the consolidated revenue requirements of the various portions with the remainder going to pay down debt. I guess the question we have is: What incentive is there to limit you to the revenue requirement or in other words, is there anyway that you are going to be able to access the, for want of a better term, the surplus in the revenue pool? MS. FRANK: A. What's going to happen is whatever the Ontario Energy Board determines is appropriate as a revenue requirement for the transmission and distribution companies will be the revenue that gets assigned to the these companies. No more, no less. Q. You won't be able to access it on an after-the-fact basis? A. No. MR. BRYAN: Thank you. That's the only question. MR. HARDY: Thank you. Are there other questions? Go ahead. MR. WALKER: Scott Walker also from ECNG. Q. Really a semantical question having to do with the capital development costs. I heard earlier that there were some modifications and some policies and procedures whereby customers were required to contribute to certain new capital installations. Along that same vein my understanding is that if [Questioning] 934 Participants there are relocations from MTO highways or from regionals -- regions, municipalities, that sort of thing, that those costs are, in fact, recaptured back? Is that the case with Ontario Hydro? MR. SURI: A. We have agreements in place with the Ministry of Transportation of Ontario right now that when we relocate cost there is a capital contribution given by the ministry to a portion of these costs. If my recollection is correct that we get, we must support the labour cost and the cost of any labour saving devices, and other than that those costs are borne by the distribution business. All these agreements, along with some of the customer connection policies are currently under review and certainly the Ontario Hydro Services Company board will have to look into these things. Q. Very much on a related note, I thus have to assume that those are net numbers then of the difference? A. The capital numbers are net numbers. Q. Okay. MR. WALKER: Fair enough. That's all I have. MR. HARDY: Thank you. Why don't we break until 2:30 and then we will begin with the Board Staff questions. ---Recessed at 2:13 p.m. ---On resuming at 2:30 p.m. MR. HARDY: Why don't we begin with our Board consultants questions. [Questioning] 935 Board Staff/Consultants MR. HOPKINS: Okay. Thank you. QUESTIONING BY BOARD STAFF AND CONSULTANTS: MR. HOPKINS: I guess I'd say to the audience if there was something that you felt that you wanted to annotate on a question, please sort of I guess indicate that. I don't mean to shut you out by talking. Q. Some more. I want to go back to something that became -- I may have asked before but became a little more apparent this morning because as I look at the schedules we handed out about the programs that were resulting like for asset condition assessments and meeting the various needs and the SCADA and the DOMCAMS system and environmental programs where you displayed, you know, the expeditures for various items here between OM&A and capital. I wondered if you could just sort of provide so we understand it, you know, an explanation of how you are looking at programs and deciding what is capital and what is OM&A. And if you look at page 22 of what was handed out this morning or 24 or 26 you see an indication of activities being -- some being categorized as OM&A and some being categorized as capital. Is there some guiding principles we could just, you know, have you articulate for us? MS. FRANK: A. There are definitely guiding principles between what gets capitalized and what gets expensed. [Questioning] 936 Board Staff/Consultants Stated very simply, it would be that anything that extends the life of the asset gets capitalized and anything that leaves the life of the asset as it was gets expensed. That's in simplest terms. I believe that we did provide some of the accounting policies that we generally use that was filed in -- actually in the distribution it's attached, appendix 2, where we have got some of policies are in there. Over time having applied that general principle, it is now clear when we do a lot of work -- like the pole replacement obviously extends the life of that particular structure and would be capital. So over time the general principle has been applied to various types of work and it's quite easy for people to determine is that a piece of capital or is that a piece of OM&A. Q. For example, just looking at the asset management information programs that you laid out on page 24 of the document you handed out this morning, you indicate that much of that is being capitalized, 45-million, but the data collection needed to implement that program is a one-time affair but it is going to be expensed. I sort of wondered why that needed to be the case. Why wouldn't that data collection have a life or something like the other equipment you're buying? A. With data collection it happens as a normal ongoing activity. When we do any other work we gather [Questioning] 937 Board Staff/Consultants information on the condition of it or on what has been done to it. When we do a piece of work we track how much material went into that piece of work. This is all part of data collection. We certainly would not capitalize the data collection that happens on an ongoing period. This is, indeed, a bit of an intensive effort of data collection, but the same basic principle applies. It doesn't extend the life of our assets in anyway that we are collecting the data. So it gets -- we expense it. Q. I looked at that and maybe I am misconstruing what that data collection is. I thought it was an enabling feature of having the system operate. Much like a planning study is part -- is a necessary part of perhaps a capital, the extension of facilities and you might capitalize the planning part of it along with the facilities so -- or an engineering analysis that was predicate to the construction. Am I misconstruing what this data -- what this type of item is or... MR. SURI: A. In the DOMCAMS, one of the items that I think probably I can add there, is the data conversion which is the enabling kind of activity which is capitalized as part of the DOMCAMS. So DOMCAMS, the total expenditure of $19-million in 1999 includes the conversion of data which is the enabling for implementation of the system. Susan is correct in pointing out the data [Questioning] 938 Board Staff/Consultants collection, the 9-million, is an OM&A item which is not an enabling for DOMCAMS. Q. What is it, then? A. It is -- when we started looking at the data we were going to collect this data to start with whether we had the DOMCAMS or not. The question was when we started looking at the assets, it is the identification of some of the assets as opposed to conversion of the maps which we have and pointing out the feeders on those maps and being part of it. So it is the exercise of going through really looking at individual assets as opposed to converting the data which we have and put them in the system to automate the system. So that's the distinction there. Q. It seems like -- to me if seems like a fine line. It's going to have a useful life of this system, is it not, having done that or something? A. Yes. I think the discussion we have had internally about that was that data collection program had started earlier than 1999 and we weren't thinking about DOMCAMS at that particular time. The ruling was that obviously we are not creating any asset, we are basically collecting some data, and that should be expensed. Some of the data in there we may be able to use it, but it is not an enable thing for the DOMCAMS project. Certainly it would be input at some stage. [Questioning] 939 Board Staff/Consultants Q. As we look at maybe some other programs like on page 26 where you're doing environmental programs and, again, we see a mix of expeditures related to that capital and OM& -- something I guess I was also interested in the distinctions there, why they were considered to be OM&A versus -- considered to be capital particularly -- well, just, for example, the pole program, you go out and find which poles you have to replace and then you replace them. Obviously, I understand the replacement of them is part of the capital program, but I guess I don't know whether the accounting rules would say that finding out which ones to replace would also be part of that. It would not? MS. FRANK: A. No, because it doesn't meet that criteria. If you go out and check all the poles, if they are penta-poles or not, have you extended the life. At the end of it you've got a survey that tells you which ones were penta and which ones were not, but have you extended the life of our asset after you have done the assessment and the answer is no, you haven't. It is not until you start to replace the poles that you extend the life. So on that one there is a million dollars doing the survey, but the survey itself does not extend the life. You don't capitalize it. The replacement does, so that you capitalize. Q. Backing up just so I can cover all of them like the two piece insulator program shown on page 22, the wood pin replacement as well, amounts shown there. Those [Questioning] 940 Board Staff/Consultants aren't life extending programs, I take it? A. There's -- I would draw an analogy to cars in saying when there are parts that are capital replacement type parts and there are parts that are normal maintenance associated with it. They don't extend the life, but you know that, indeed, when you have a car you're going have to do some regular checkups and maintenance on it. We go so far as to identify what pieces of our assets are -- we use the term called plant retirement units. Those items get capitalized. We did do an assessment as to what parts of the system are appropriately capital and which ones are the maintenance activities. Q. That's what I thought, like a wood pin might be a special program because they are not any longer common and you are going back to replace them and, therefore, the life would actually continue. I mean, it would be an improvement on the life because wood is -- has a much lower life than what you are putting back, but I'm not sure what you are putting back. A. That's not a big enough portion to extend the life of the asset. Q. Because you have a -- it is a pole and cross arms or something is the unit of property and this is only a piece of that unit of property, is that it? A. Yes, and it will not extend the life of the structure. Q. The same would apply to this insulator [Questioning] 941 Board Staff/Consultants capital-- A. Yes. Q. --program as well? A. Yes. Q. There is a difference, of course, in the effect of cost to the customer as you make this choice between capital program and expense program? There is a significant difference, yes? A. There is. Q. Okay. Thank you. Moving on, just looking at the capital programs for a second. As we saw them, and I think somebody referred to them a bit earlier in the December 7th filing, the large filing for distribution where you displayed the capital work program amounts on table 8.6, I think it was page 52, they show various totals by category of sustaining, developing, operating we've been talking about. The materials that you presented to us here more recently, the January 4th materials, also show details of those programs and I guess we've noted that if you look at the programs presented in the January 4th materials which were under I guess -- I would say under tab I; is that right? Yes, tab I. Those that are labelled -- those that are labelled sustaining and distribution support seem to fall short of the total shown on page 52. The sustaining programs add up I believe to some [Questioning] 942 Board Staff/Consultants 7-million less in each year and the distribution support programs add up to 13-million less -- 13.5-million less in '99 and 7-million less in 2,000. Are these changes or are they just omissions or what's what? MR. HARDY: Just allow our panel to get caught up. MR. HOPKINS: Yes, sure. MR. HARDY: Are you referring to pages about 90 on in tab I? MR. HOPKINS: Yes. I believe that would be -- 90 on would be the sustaining programs, right? I think so. 90 through to 104 of tab I. MS. FRANK: Why don't we start with the distribution support and then Vipin will handle the sustaining after I do the distribution support, okay. MR. HARDY: Where are you on distribution support? MS. FRANK: I'm just going to have to answer his question because I don't have filings on the additional information. MR. HARDY: Okay. MS. FRANK: What we filed on - on the distribution support where the big programs that we have which was the process enhancement program which -- I will use 1999 numbers to go through, if that's okay with you, Bill. MR. HOPKINS: Q. You're what? '99? [Questioning] 943 Board Staff/Consultants MS. FRANK: A. '99. Q. Okay. A. So that project would be called PEP was $10.4-million. We also filed information on the infrastructure project $3.8-million -- Q. You are looking, excuse me just one second, you are looking at the -- A. I'm referring to those items that were in the "I" section and I'm just trying to get us up to the portion that we did file detailed information on and then I'm going to tell you about the items that we didn't which is really what your question was. MR. HARDY: Sorry, if I can follow. Working through "I" to get us to the totals that are on table 8.6 on page 52? MS. FRANK: Yes. MR. HARDY: Under distribution support. MS. FRANK: Yes. MR. HOPKINS: Q. So you are starting on page 127 of I; is that right? MS. FRANK: A. That sounds like about the right number. Let see if I can find that. 127, that's correct. MR. HARDY: It feels like I'm at church here, everybody is at the same page in the hymn book. So we have page 127 under tab "I," we are starting there, and we also keep open page 52 on the December 7th filing. MS. FRANK: Good. [Questioning] 944 Board Staff/Consultants MR. HARDY: Okay. Go ahead. MS. FRANK: Through tab "I" what I was doing was listing the projects that we did provide information on and I want to characterize why we did. Let me finish off the description on page 130. We had the human resources and process re-engineering system with 9.8 and then the pay system on page 132 was $7.48-million. All of these were large projects that materially change the nature of the work. They are kind of one-time let's put in a new process, a new system, a new pay system, let's re-engineer the HR systems, let's get new financial and work management systems. They are one-time significant efforts. There is also ongoing work and the ongoing work we didn't provide capital listings on. The piece that you are missing each year that's not in there is MFA which in 1999 would have been in the order of $5-million. That's not -- we didn't do an MFA work program description, but if you want to know what MFA would be it would be computers, transportation and work equipment, some office furniture. That sort of thing would be the amount of fixed assets. The other thing that we have in there, particularly in '99 which is different than the other years, is some office enhancements associated with a planned office relocation as this organization has to move offices in 1999. We will have to do some enhancements to [Questioning] 945 Board Staff/Consultants the location that we'll capitalize and those are the -- we didn't write up separate pages on those programs. MR. HOPKINS: Q. I wonder, is that something you might be able to provide just to sort of fill it all out for us here? MS. FRANK: A. I doubt there would be any history on -- I mean, it's quite a different nature of an activity. I would say that those were projects that you justify, that you have to make a conscious decision on. Minor fixed assets, I believe, are an ongoing necessary part and every year you have minor fixed assets. But if you're saying a page that would identify what minor fixed assets are and what the total dollar spending is in that period, I mean, that's -- I guess I'm wondering, does that add value? If it does, I certainly could do it. Q. Well, tying it all out, it would seem to add value leaving -- I mean, I realize it isn't the biggest item in the $13-million, but still, it's -- it isn't insignificant. It's as big as any of the ones that you've identified and I thought, you know, maybe there was some -- left without it, you wonder if there was some change in the program. Your explanation has been helpful, but minor fixed assets, I presume, have some history to them as well though. No? A. Yeah. There's like three -- between 3- and $5-million kind of every year, and if that's -- I mean, I can do a page. We hadn't included it because we didn't [Questioning] 946 Board Staff/Consultants see it in the same nature as a capital investment. But if you want a page, I can do it. MR. HARDY: Well, I'm hearing the consult ask for it and I understand it is possible to bring it forward. Is it acceptable to do that then? MS. LITT: Do those two items explain the complete $13.5-million difference? MS. FRANK: There's -- in one of the years, I have a small amount of information systems work that I'll add to another page. I will explain the full difference. MS. LITT: Good. Thank you. Similarly for the $7-million difference in the year 2000? MS. FRANK: Yes. MS. LITT: Thank you. MR. HOPKINS: Q. And then the distribution support missing piece there, pieces or -- sustaining, excuse me, sustaining program. MR. ROGERS: A. Do you want me to answer that? Q. Is there something? A. I believe missing in the filing was, there was one on capital -- I'm sorry, on storms for 3.3-million, storms and damage claims and filed, I believe, in with the transmission data was the information on transformers, regulators and the like, which was another 3-million and that should ... Q. That's in, as you say, in the transmission page? Do you have a page that -- [Questioning] 947 Board Staff/Consultants A. Page 88. MS. BULKLEY: Page 88 you said? MR. ROGERS: 88, that's correct. MS. BULKLEY: Okay. MR. HOPKINS: Q. Well, I guess again, it would be helpful to us to sort of fill out -- MR. ROGERS: A. We can supply you with whatever... Q. ... with whatever programs you could provide in that regard so that we can see it, you know, in the best explanation you have for it at this point in time, I'd appreciate that, if we could do that. Also, you know, we note that in these programs, of course, we have limited reference to what they were before. It was -- you know, it was helpful, as you are aware, to see -- you know, in the distribution side, you know, some reference to some of these programs, what they were before in prior years. MS. BULKLEY: I think this is something that we had requested before to -- maybe Susan knows the status. MR. REGHELINI: Yes, we've gone back and looked at all of those program descriptions and where there was historic information, we're bringing that forward. And as John said, the missing capital program, we're bringing that forward as well. I believe it should be available tomorrow. MS. BULKLEY: Thank you. MR. HOPKINS: Q. Let me turn to a subject that I [Questioning] 948 Board Staff/Consultants was discussing with you briefly this morning about balancing accounts. Due to the uncertain nature of the revenue requirement here, it's all forecasted going forward in a sense, but it's described why it's there. I understand that. It could be that the Board would look at this and suggest that a certain percentage of it be put into a deferral account and I just wanted to know if you had any comments on that, that type of a process where the deferral account, of course, would be -- traditionally what a deferral account might be, that it would be allowed based upon some proofs at some later date or disallowed. MR. SURI: Do you want to answer that, Susan? MS. FRANK: A. I don't think we've given the use of deferral accounts a lot of consideration. I guess we believe that what we're putting forward is an appropriate program and an appropriate level of expenditure on the distribution system and -- I mean, certainly if -- we expect that we're going to come back and report on that and indicate what we've accomplished after the year is up and report on what work was undertaken. At that point in time, I'd certainly think the Board would have every opportunity to reflect upon the work that we accomplished and that may accomplish the same thing as a deferral account and be -- particularly since I expect that we're heading into a different form of regulation might be the more appropriate way to handle this rather than setting up deferral accounts. Q. There's always some uncertainty in the [Questioning] 949 Board Staff/Consultants revenue stream on a traditional revenue projection basis because it's guaranteed as you described earlier this morning. We're going to take -- if this 200-million is allowed, you're going to take 200-million. Whether it's a sunny day or a rainy day, cold weather, hot weather, the programs proceed as expected or not and it was just a thought that might give the Board and, in effect, the public, and the customers, some control over the fact that the programs did or did not meet expectations or did or did not exceed -- you know, did or did not progress as expected and that there would be necessary proof at some later date for that. A. I guess I'm questioning, Bill, the advantage of the formality of setting up deferral accounts and the tracking and all the effort associated for what I believe is a relatively short period of time and that I'm not suggesting that we wouldn't provide any information back at the end of the period saying what has been accomplished or did we spend what we said we were going to spend and then the Board always has the opportunity to make their own judgment upon that. Q. That's mostly prospectively, is where it's going. This would be retrospectively in a sense. A. If we were in this form of regulation for the long haul, I think there would be more merit in considering it, but since there's every expectation that the Ontario Energy Board will regulate their distribution systems - not only us but others - with a new form of [Questioning] 950 Board Staff/Consultants regulation, that I wonder about setting them up at this time. Q. Did you have something you wanted to ...? MS. BULKLEY: Yes, I just wanted to follow that up quickly. I guess I understand that to mean that if the Board were to go down such a path and say they wanted to set up, you know, a deferral account, does that then mean whatever total revenues the Board approves to you will be what you need -- you're working with going forward; in other words, Finco wouldn't be supplying you the difference between the revenue requirement that was provided to you by the Board and what you asked for? You would go -- you would have to make blanket -- your cuts of some sort in your programs? MS. FRANK: We'd certainly have to take it back to our Ontario Hydro Services Company Board and determine if there was -- I question that they'd be willing to allow us to spend money where we didn't get it authorized through the revenue requirement, but I can't prejudge what our Board will say. We would definitely take it back to them. MR. HOPKINS: Thank you. Q. Moving along, I wanted to look at some of the joint -- somebody mentioned earlier the joint-use programs. And I notice there is a capital program for that under tab I. Page 94, I believe, it's shown on. First off, I wanted to -- I think I heard the [Questioning] 951 Board Staff/Consultants description of what joint-use is, but if you wouldn't mind giving that again, I'd appreciate it. Joint-use work is related to poles or things that you own with utilities, other utilities, or share the use of? MR. SURI: A. Yes, it is. John, do you want to describe that? MR. ROGERS: A. We have joint-use agreements with -- I'll use, for an example, Bell Telephone, and the agreement there is in an effort to get efficiencies and have one pole line going down one side of the road instead of having one on each. We've come to agreements with Bell where they will own some of the poles, we own some of the poles. When they want access to our pole lines under certain conditions, they fund a certain portion and we fund a certain portion and the same. So what it is, it is a cost-sharing agreement to get efficiencies for both companies and both benefit from it. Q. Would it also apply to cable companies, for example? A. We have rental agreements with cable companies as well. Q. I see. And those revenues are brought back in against the cost of service, are they-- MS. FRANK: A. Sorry. In the joint-use case -- Q. --for sharing the capital costs ... A. Yeah, the costs aren't there, so ... Q. But in the case of, say, a cable -- [Questioning] 952 Board Staff/Consultants A. Yes. Any -- part of the recoverable work is -- that's how we categorize it. We call it 'recoverable work' where, indeed, we've got rental for any use of our facilities, of any of our poles by cable companies or anybody else who might want to use our poles to string something. Q. I see. I was in one of your subsidiaries a couple of years ago -- no, it's in a different country, but it -- cable use was -- I think I stood at a pole and counted 17 attachments to it and the utility was suggesting that that wasn't much of a -- there was no added cost to that because the pole was already there, but quite frankly, it was well guyed as well. So those rental things come through for the joint-use relocation,. Do those revenues go to -- are those negotiated tariffs that you have with these people or how do you set that fee for my hanging a cable on your pole? MR. ROGERS: A. Yes, they're -- I'll give you my understanding of how it works and I may have to come back to it later. My understanding is that with the cable television, that there's a general agreement with a variety of different cable television companies for a pole rental fee and that it's applied to a number of companies. It's negotiated between Ontario Hydro and the cable companies as a group. Q. Is that regulated in any fashion? MS. FRANK: A. I don't believe there's any regulation on how this works. The dollars aren't big. [Questioning] 953 Board Staff/Consultants Let's put this into perspective. Actually, if we turn to page 123 and we look at 'other revenues, is how we characterized it, so section 16 -- I'll just wait until you get there. Now, the first line in that table is recoverable work and in 1999 you'll notice that we have $54-million. Of that $54-million, $6-million would be related to this activity. So it's not kind of in the scheme of what we're talking about. Q. Thank you. I guess the only other question I had was, as we look at this distribution program here for joint-use and relocation, is there data that would -- and I guess this is something we're going to see perhaps -- there is data perhaps that would show us what it's been in an historical sense coming forward; do I understand that right? We're going to see some data for 1998 or what you can do here for this kind of program? MR. REGHELINI: A. On recoverable work? Q. On the joint-use -- well, on the joint -- not recoverable work but on the joint-use facilities program. Excuse me, I went -- A. I'm not certain about that specific program, but as I said -- Q. The $8-million a year which seems to be a fairly constant level here at least for two years. A. We did go through all of the programs and the ones that didn't have historic information that we could [Questioning] 954 Board Staff/Consultants obtain historic information, we are bringing forward tomorrow. Q. Thank you. MR. ROGERS: A. In the background, it notes that historical costs have averaged $8.5-million and -- but it does vary depending on the amount of roadwork and a variety of other work that are going on. Q. Skipping to another program which I have on my list. Let's see. The program shown on page 108 of appendix I which is the distribution capital program for customer additions, connections, et cetera, et cetera, again, would we be getting -- we'd be getting some historical perspective on that, I guess, in the upcoming information. And would that perspective indicate, you know, the number of entities being attached and upgraded and removed as it were per year as well as the amount of dollars spent? MR. URBAN: A. That's actually covered in the submission, page 65-- Q. I see. A. --with numbers of connected customers. MS. BULKLEY: In the original filing? MR. HOPKINS: No. In the supplemental, I see it. Okay. Q. Okay. So you are going to give us an idea of the capital cost going back on that as well? MR. REGHELINI: A. On this particular program, [Questioning] 955 Board Staff/Consultants my understanding is that historic units were available and that's why they were provided. There has been some difficulty in coming up with historic costs because the way the information was managed was, as Vipin had spoken earlier, with respect to eight utilities and the -- coming up with consolidated historic cost data has proven to be difficult. So without a lot of manual searching, coming up with historical costs on this one would not be possible. Q. It's not a terribly pertinent item. 6500 customers who cancel service? That's the first time I've ever had that drawn to my attention, that that happened, so ... What is that? MR. URBAN: A. My understanding from the people that do the work is that -- generally, that's services removed from buildings that are being torn down, abandoned and that sort of thing. Q. It makes sense. You mentioned that there were programs - we talked a little bit about losses this morning. Somebody questioned the system losses in the programs that were set forth. Certainly identifying system losses, the SCADA and the DOMCAMS -- the SCADA system in particular was going to help you identify the losses though we've carried the estimate of losses forward in this -- in the capital programs you have here. So is the implication that in the short run, [Questioning] 956 Board Staff/Consultants we're not going to be able to be changing the loss levels by these programs? A. Yeah, I think that's safe to say in the near term. I'd also add that our reading of the market design committee work suggests some future methodology, consistent methodology, for a loss calculation allocation and all that sort of thing, so we probably have a different future to look forward to in this regard. Q. Just to cover a question that I had before, when you -- you've mentioned in many of the descriptions here that reliability is driving some of the need for, you know, continuing or improved reliability is driving some of these programs, the need for these programs. Are there -- with each of these programs, it doesn't mention it and I take it it's because it's not really inherent in it, that there is a specific measure of expected improvement and reliability given the fact that the program is undertaken. Is there -- was that kind of detail developed in... MR. SURI: A. Not yet. That kind of detail has not yet been developed. As I had mentioned, that we are looking at the reliability as a measure. It's being developed not only in total and eventually I think it can also be looked at from a program perspective. Eventually there needs to be a link between the programs and what impact it's going to have on reliability which we don't have at this time. [Questioning] 957 Board Staff/Consultants Q. Within the history, this morning we looked at the history of what was being done in the programs on the line replacement with the line additions and pole costs and that type of thing. It seemed like there was a dramatic, you know, suppression of those taking place in a period of time. I take it that was at the direction of the board of Ontario Hydro and what have you, but you mentioned there were other demands on the system. Were those other capital programs in the generation area? A. Yes. I think the programs for Ontario Hydro were developed in light of the priorities of Ontario Hydro. So certainly, yes, there would be some capital programs on the generation side which had an impact on the capital programs on the distribution and transmission side. Q. Or was spending in total brought down as well? A. Total spending went down and plus there were competing priorities on the reduced spending base. Q. So some of the programs we're now seeing added in might be reflect programs that were previously rejected and now part of having an ability to afford them or an apparent -- a hope -- an ability to their being brought back? A. As I said this morning, I think it is a combinations of two things. [Questioning] 958 Board Staff/Consultants Yes, some programs probably are coming, but the key here is in 1997 when we started really looking at some of the programs, so it was not that programs were submitted and they were not approved by the board. In many cases programs were not even proposed because they did not a systematic way of looking at it. So perhaps the combination of those factors. Q. For example, the SCADA program, was that -- I mean, this SCADA system, as you mentioned the many utilities have SCADA systems and what have you. Was that previously proposed? A. No, it was not. Q. It was not? A. Because the management was done on an individual utility basis and none of the utility managers could really -- proposed anything that they should have the SCADA system. They were relying on the local knowledge and some anecdotal information which they had. Now that we are looking at it on a provincial bases, certainly I think it is a program which is being proposed now. I guess looking at the SCADA program just a little bit further, it is indicated there is going to be a pilot part of the program and then we're going to roll it out a little more fully. Why are we -- what's the nature of this very short-term pilot program? I mean, why is that necessary or why do you think it's necessary? [Questioning] 959 Board Staff/Consultants A. What's happening is we are also looking at the total infrastructure of information technology in the Services Company. SCADA is also going to have an implication on the communication needs or what kind of communication facility should we have: should it be land based or should it be other means of communicating. Both with DOMCAMS and SCADA, what we are doing is conducting a pilot which would be finishing at the end of June this year. And after the completion of the pilot, then we will go back to our own internal board for approval of the final SCADA program and the DOMCAMS program. The need for that was felt that these kind of programs do require a lot change management kind of initiatives within the field. The life in the field which was there, they were doing certain things that's going to change. Rather than looking at the whole province at this point in time, we said: Why don't we look at one part of the province at this stage for DOMCAMS as well as SCADA, look at all the initiatives and change management. In the meantime, the Services Company would be ready with information technology architecture which is still being developed and we'll put all the pieces together. So we will know the impact on staff, the change management issues the company is going to be facing. We will have an experience on a smaller geographical base within the province, too. [Questioning] 960 Board Staff/Consultants It is the IT needs and the communication needs. Once the architecture decisions are made, then we can finalize on the hardware and software, although for DOMCAMS the initial selection has been made of a software, but on the condition that if it does not meet with the final architecture which is being developed, then we will have to go find a different solution. So the things were happening in parallel. So it wasjust to make sure that everything fits in we had decided we would conduct a pilot. Q. So you haven't committed to the full expenditure that's shown as yet? You are not committed to some expenditure anyway? A. The commitment and approval I have received is for the pilot. Q. You have approvals. Yes. A. And the total commitment of the program will go back to the Ontario Hydro Services Company board at the conclusion of the pilot. Q. So we haven't bought a piece of equipment; we may have to -- A. No, we have not bought and we have not committed things, that's correct. Q. You mentioned a communication system review, and I know I'm jumping out of my order of sequence here, but that sounds like something that is of interest to me because I saw a very expensive program just put together by a utility in the United States, a communications -- [Questioning] 961 Board Staff/Consultants radial communications system. Is a new system here reflected anywhere in your budget program? A. No. Q. So that would be something yet to come? MR. SURI: Doug, do you want to answer that? MR. URBAN: A. I guess I should just maybe briefly explain the nature of the SCADA project in that it is really quite a trimmed down version from what SCADA normally is. SCADA is supervisory control and data acquisition. Mostly we're doing data acquisition, so the supervisory control is very minimal. The other thing is that we are contemplating a system where we only communicate part-time with these 940 stations. If they have something significant to report they communicate in. So the communications that we are looking for, you know, are some version of maybe some of our existing telephone circuit technologies and things to support that kind of operation. It's not certain exactly where we are going. Up in the north, for example, cell technology isn't available. So that's basically what we are looking at. MR. HARDY: I wonder if it would be an appropriate for me just to poll and see if -- MR. HOPKINS: Sure. MR. HARDY: Are there other questions from participants that might have arisen as a result of the [Questioning] 962 Board Staff/Consultants Board Consultants' questions? ---(No response) Why don't you continue. MR. HOPKINS: Continue. Q. Maybe you mentioned it this morning, but the cost savings that flow from the DOMCAMS system are not included in any of the numbers we are looking at at this point in time and they would be prospective beyond the Year 2000, is that-- MR. SURI: A. That's correct. Q. --my understanding? Do you have any estimate of what those would be? A. That's a difficult area at this point in time and we have been looking at a number of other companies who have implemented a similar kind of GIS and outage management systems and trying to learn from their experiences what is going on. Most of them have been able to identify -- the items you probably would result in saving, items might be efficiency in dispatching the work. At the moment, when a trouble call comes in we issue a trouble ticket. You may be able to combine the trouble tickets and issue only one trouble ticket to the field. Those kinds of things. In terms of arriving at different numbers, I think that's where some of the difficulty is because we have a number of other initiatives going on which is also examining the redesign of the processes. The numbers which I've heard, I could probably [Questioning] 963 Board Staff/Consultants provide a range from anywhere from $3- to $5- $6-million per year savings. That's what the other utilities have indicated to us, but we've not really looked into that. Part of conducting a pilot is going to be a finalization of business processes which we will use for outage management. Once we know what the processes are, then what we can do is look at the cost of knowledge management process today, what would be the cost of the outage management process tomorrow and then the difference can give us the savings. But the indication from other companies are that there are areas where definitely there are going to be savings. Certainly you are looking at synergies in the field from a field planning point of view. So ... Q. My normal, I guess, expectation in proposing a fairly major program you would have presented some ballpark figures of cost savings attendant with it in order to justify it. A. Yes, I think one of the things we've looked at with the DOMCAMS and SCADA kind of project is, dealing with that, if we are going to continue managing these assets, the information about the assets, their conductivity, is an essential part. So it's not sort of a revenue enhancing kind of capital expenditure. It's looking at what other alternatives you have. If you do not put SCADA in place, then how would you meet the needs of customers? How you find out?. So compared to that, I think the SCADA option [Questioning] 964 Board Staff/Consultants certainly was the better option and, again, this is based on -- my understanding is there are about 70 to 80 per cent of large distribution utilities in North America have invested something in a system like GIS and outage management system. And many others are really looking at that because if you are looking at automating your processes, if you are looking at finding information about your assets, increasing the responsiveness to your customers, that's the kind of items in which we are doing that. And too, one of the things we need to look at is because we have a number of other systems already in place within the corporation, like the customer care system, expenditures have been made last year into a work management system. SCADA is going to be put into, as one of my slides indicated, in the middle of all that to automate the operation management. And the key part is, is the interface requirements with these other systems and also designing on what the final processes will look like, gives us a little bit of a difficulty saying what exactly the numbers are going to look like from a savings perspective. We definitely, from the experience of the other companies, and the vendor we are dealing with right now have indicated that certainly once you implement it and develop interfaces, that your cost of managing outages, your cost of dispatching work from today will definitely [Questioning] 965 Board Staff/Consultants decrease and the range they have given to us is somewhere, as I said, you know between $3- to $5-, $6-million range annually. Q. Thinking of other major programs you have laid out here in your distribution support area, your PeopleSoft program, looking at page 132 of Appendix "I" where you have your PeopleSoft program of $7.5-million that you are cloning, I guess, from an existing program and what have you. I guess I'm sort of -- this program already exists, as I see the explanation here for it. You know, it exists in the Ontario Hydro system and maybe the Genco has it or something of that nature. I mean, why, if we already have it, is it going to cost $7.5-million to clone it? MS. FRANK: A. We're not talking about the PeopleSoft system here. We're just talking about the HR PeopleSoft system, that component of it, right, because we have another performance enhancement which is also people soft. It is just the HR system that you pay. Q. Okay. A. On page 132. MS. BULKLEY: That's right. We have similar questions about the other program as well. So to the extent you can answer them simultaneously... MS. FRANK: I likely can't. MS. BULKLEY: Okay. MS. FRANK: So let's talk about the page 132, the pay system. [Questioning] 966 Board Staff/Consultants The $7.5-million is actually the cost to make this system -- they call it cloning it, to have a separate application of it that we can run within Ontario Hydro Services Company. It would cost a fair amount, more than that if we were to start over and try to develop a PeopleSoft system with our ability to manage our collective agreements, and it certainly cost Ontario Hydro in developing the overall Ontario Hydro system a lot of money. So I don't have the exact numbers, but I do know that when we have explored how much would it cost to allows to us run the system separately, that this is the cost to allow the Services Company to use this system. There will be effort required in order -- we can't just say we've got it running for Ontario Hydro so now we will run it for the Services Company. There are modifications that are required to make that happen. The cost here is actually cheaper than sharing the costs, saying we will pay a share of the existing Ontario Hydro costs in trying to use their system. It was going to be more expensive to do that and keep the information separate. That was the cheapest alternative. MR. SURI: A comment I can add -- MR. HOPKINS: Q. It just seems odd to me that it would cost -- if the system already exists, you know, why it is going to cost more to use a system that already exists than to create a... This is creating a new [Questioning] 967 Board Staff/Consultants system, is it not? MR. SURI: A. Two points here. All the elements of the system, number one, do not exist. In future, each company would be operating under different collective agreements and the issue is not to calculate gross to net pay. I think systems -- you're absolutely correct, that you can take one system, take it from one company to another company and as long as you're living in the same country you can calculate gross to net pay. The issue becomes: How do you arrive at the gross pay? That's where the collective agreements start coming into the picture. The agreements for the Services Company are going to be a lot different in future than for the generation company and those are the kinds of things which are looked at. The corporate system was not implemented fully across the corporation to start with. So it's adapting the system to the Services Company as well as looking at the unique requirements of the Services Company that are also part of the pay system. MS. BULKLEY: Q. So the agreements that your labour people are operating under aren't in the old Ontario Hydro system, is what you are saying; that you have it adapt this in order to allow this system to compute according to those contract agreements? MR. SURI: A. It's the need to have those flexibilities for future. And Susan correct me - my understanding of the system was not implemented throughout [Questioning] 968 Board Staff/Consultants all parts of Ontario Hydro in the first place. When the system was implemented we were looking at that the time might come that we may have to separate the system and different algorithms were being developed to calculate the gross pay for the generation company and different parts of the collective agreement at that point in time. So it's not fully operational at that point in time. Q. Is this a relatively new system for Ontario Hydro? Can you tell me when that was put in place? MS. FRANK: A. This is a very new system for Ontario Hydro. We have been rolling it out kind of through our different categories of staff, and I'm not certain if we managed to get it all the way through all of the categories. I know that we've got certainly -- as we rolled it out they did it in phases. So they would have done the executive salary group first and pensioners, and then they got into some of the Society staff and getting into the Power Workers Union. I don't know that they completed the whole exercise, but it was a very mammoth effort to try to get a pay system for Ontario Hydro redesigned and that's what that was. Now, we do have -- we have separate agreements that have just been negotiated this year on a going-forward basis that we -- and right now the terms are very similar, but they could well separate as the [Questioning] 969 Board Staff/Consultants businesses separate and it wouldn't have any flexibility to deal with that. MS. BULKLEY: Maybe this is just - I don't know - an oversimplification, but did anybody consider or look at outsourcing opportunities? There are generally large banks that do this kind of thing and often can do it with economies of scale. MS. FRANK: We did do some exploration of that, but we do have very complicated agreements with many conditions of calculating the gross pay, as Vipin called it, that banks didn't seem to be very interested in dealing with because it was going to be a very complicated process to get to the pay calculation. MR. HOPKINS: Q. I know earlier I mentioned the PEP expenditures, too, and -- this is -- as I take it, this PEP project which is shown on page 127 I believe is an ongoing project -- is process enhancement performance project is what it's labelled. Is this a computer system? What are we getting here? What are we -- we're doing a computer program system? MS. FRANK: A. This is -- certainly there's a computer system as part of this, but there's also lots of re-engineering of work management processes and of financial systems. I mean, this is very much critical to having information that -- out of a system that will meet Y2K concerns. It helps us to look at all of our work and manage our work throughout the services company. This [Questioning] 970 Board Staff/Consultants project started within the services company and focuses on work management and financial systems. MR. SURI: A. I think we had a work management system and this, in particular, will be used by the network services people in execution of work. And from an asset management point of view, not only it will manage the work, it will also provide us the information in the level of detail the asset manager would require about the programs, so ... and the existing systems which we had were not Y2K compliant and this was one area that needs to be looked at and this system certainly will meet the work management needs and all the reporting needs for the asset management group, both on distribution and transmission side. Q. Let's see where I am on my list here. I think we want to look a little bit more at some more individual programs here. MR. HARDY: Bill, I just wondered if I can get a sense of how long the questioning will be so I can judge whether we'll have a second break this afternoon. MR. HOPKINS: Well, I think we'll be done within the hour, but I mean ... MR. HARDY: Within the hour? What if -- MR. HOPKINS: She's suggesting it may be another half hour, too, maybe an hour and a half or something of that nature. MR. HARDY: Okay. Why don't we take another 15 minutes anyways? I sense the energy level in the room is [Questioning] 971 Participants down a bit, so we'll take 15 minutes and maybe consider another break then, okay? We'll break for 15 minutes. ---Recessed at 3:30 p.m. ---On resuming at 3:46 p.m. MR. HARDY: Are there any questions from participants before we get back to Board consultants? QUESTIONING BY THE PARTICIPANTS: MR. STEPHENSON: I have a very short question of clarification. Richard Stephenson. Q. In terms of the -- we were talking earlier about some of the historical data that we're going to get tomorrow, I think it was, some information about historical costs and programs and stuff? MR. REGHELINI: A. Yes. Q. Okay. In that, I'm particularly interested in the sustaining capital numbers. Is that part of that package? A. Yeah, those programs are primarily sustaining capital programs. What it is, is, some of the programs in that supplemental filing I identified what average historical expenditures were and some of them didn't. And just to be consistent, we've gone back and where we could get historical information for the ones that we didn't have in the original supplemental filing, that's what we're providing. Obviously for the programs that are new, there is no historical information, so there won't be anything coming in on the new programs. [Questioning] 972 Participants Q. I guess the question I had is, that in terms of the presentation of the information, are we going to get information presented in the same kind of categorization that appears at -- for example, at page 13 of your handout for today where you talk about the broad categories of sustaining development, operations and so forth? Are we going to get the information presented in that format on an historical basis? A. What we are filing are revised pages to supplemental filing I, so it's all in that format with the additional line added in saying what the historical average expenditures were for those particular programs. MR. HOPKINS: A little bit more detail. MR. STEPHENSON: Yes, more detail than I want. Maybe I can just follow that up then while I've got the microphone then. Q. Just turning to page 13 then of your material for today, on the sustaining capital figure, the figure for 1998, I gather, is as high as it was driven, in part, by the ice storm expenditures; is that -- MR. SURI: A. That is correct. Q. Do you know what the -- but for the -- and I take it what you did was, you took some of the money that you had budgeted towards other sustaining programs and you redirected them towards ice storm repair as a practical matter in 1998; is that how you dealt with it? I mean, you obviously didn't budget for ice storm repair. A. Well, some of the work which was planned [Questioning] 973 Participants under lines and stations was covered as part of the ice storm to start with anyhow at least in eastern Ontario where we were doing that and the two -- we had a number of resources which were directed towards the ice storm, so it was the question of the work being done on the ice storm and it was a strain on resources because a lot of people were working on that. So with the results -- we had -- I think when we prepared the graph, the number for facilities, which are lines and stations, would be 22-million there. That's the expenditures we had incurred in that category. Q. Yes. If we took the -- generally speaking, in terms of looking at your sustaining capital program in prior years - that is prior to 1998 - in constant dollar terms, were the numbers more or less the same as the 1998 figure; were they lower or higher than that? A. Okay, I do not have any 1997 numbers on that. Q. I'm not looking for precision in ... I'm more interested directionally on this kind of issue. MR. ROGERS: A. I have no other information here at this time other than what has been presented. You want to know in the past, generally speaking, were they up or down from that level? Q. Yes. Is that something which is -- presumably it's achievable if you add up the various figures that you're going to provide to us in addition to what you've done already, but is it possible for you to get back to us generally with that answer? [Questioning] 974 Participants And I'm not looking for dollar amounts, but it would be useful to know if 1998 was, you know, 20 per cent more than the historical ten-year average or if it was 20 per cent less or if it was about the same. A. I'll take a look at what information that I'm able to find and bring it back. MR. STEPHENSON: I'd appreciate that, thank you. MR. HARDY: I'm not going to note that since we're not aware if that information exists. MR. STEPHENSON: We know it exists. It's a question of whether they add it up or not. MR. HARDY: Okay, sorry, yes. But I'm not going to note that as an information item coming forward. It's on the record though. Okay, thank you. Why don't we turn to Board Staff? QUESTIONING BY BOARD STAFF AND CONSULTANTS: MR. HOPKINS (Reed): I'll only go through a few more programs and then turn to just a couple of other items as well. Q. The PCB replacement program that was talked about, I think, earlier this morning which is shown on page 95 of supplement 'I' as being several million dollars a year, reflecting the replacement of about 1100 transformers annually, it sort of indicates that it's going to be a multi-year program of five years or something of that nature and I don't see how that addresses the 13,000 entities that you think are -- or estimate that need to be remediated. If you're only going [Questioning] 975 Board Staff/Consultants to do a thousand a year, it seems to me like it would take close to 13 years. Is there something I'm missing or -- or is it uncertain -- is it the uncertainty of the number that might be affected? MR. ROGERS: A. The number of transformers that the program has shown here should remove from service would be around 1125 on an annual basis. There would be another 50 transformers that are taken out through normal attrition, lightening and that type of thing. So there would be something in the 1175 under this program at the present funding. As well, there's the issue of the transformers that are being identified and removed from sensitive locations may not be as efficiently removed as if you were going down one line and taking them off one after the other, so ... Q. But it indicates that 13,000 are estimated to be contaminated. Is that the universe that you're going to try to be addressing at a thousand a year -- or 1175? It seems like it's a little short. A. It's a two-year -- the proposal that we've got here is a two-year for 1999 and 2000 and then after that, we'll have to take a look at where we're at. The program will continue. MS. BULKLEY (Reed): Q. Is this one of the programs that has a longer forecast as we talked about [Questioning] 976 Board Staff/Consultants earlier today that we could possibly get? I know it was an issue that you were going to take under consideration whether or not we could get the full projections on the capital programs. Is this one of those programs that is projected out five years and could we take a look at what the plan is? MR. SURI: A. Definitely this program is going to go beyond the Year 2000. We have not got the programming details in the future years. We have some general transfer, total capital, total OM&A. We have not really gone down at this level of detail at this point in time for individual programs and ... but this would be a program which -- I think the initial focus here is to look at environmentally-sensitive locations, locations where, you know, it may be -- having an impact that we may have some farms next door to it or some residential properties and those kinds of things and what we want to do is address all those locations by the Year 2002. And my view is that this program probably will go until maybe 2008 or something like that because -- at this rate, but certainly not really having developed the details for future years, I cannot really certainly say that. But the target in our programs we have today is that we want to complete all the sensitive locations by the year 2002 and those kind of -- other than that, we have not done the detailed programming for future years because forecasts for future years just become general trends and we really do not go through program level [Questioning] 977 Board Staff/Consultants details at this time. Q. I just want to clarify that then. The discussion that we had earlier about the programs being forecast out for a longer period of time earlier this morning, 11 o'clock or so, that was just a total number of capital for five years or was that -- I guess my assumption when we had that discussion was that it was broken down in further detail, so I just want to get a sense of what that looks like. A. Okay. I have people checking into that and by tomorrow morning, we will have something. The feeling I'm getting right now was that it's going to be total level details rather than programming level details. Like, it will give us a trend that the programs in future years are declining and this is the rate of decline essentially. MS. BULKLEY: Thank you. MR. HOPKINS: Q. The initial filing, the December 7th filing mentioned, and I was looking for the -- you expect that the program will continue over five years. Of course I was the one that mentioned 50,000 transformers as well, but even five years at 13,000, one thousand a year, it didn't seem to add up to me and that's why I wanted to find out a little bit more about it. It seemed a little short. I understand that you are going to... MR. SURI: A. You're absolutely correct, the 13,000 at 1100 per year, it's going to take you more than [Questioning] 978 Board Staff/Consultants five years, that's correct. Q. Yes, I thought so. Another program -- a similar maybe type program is what you called your pole replacement or pole replacement for -- deteriorated pole replacement program shown on page 91. And here, again, you're talking about, you know, doing some remediation to the poles, a replacement rate of 11,000 a year, but you're adding 24,000 a year in the 'old' category to the 466,000 you've already got in the 'old' category and here, again, the programs seem to be insufficient to meet any objective other than perhaps holding your nose above water and I think we talked about that earlier and that's basically where you're at this point in time I take it. A. As I mentioned, we are replacing 23,000 plus poles as a result of the whole capital program. This particular program will address 10,600 in 1999, but the other programs will address up to another 12,000 poles and those -- because when we are relocating, if we see a bad pole, we'll replace it at the same time. So it's essential when you look at the pole replacement program that we look at the total of all the poles from all programs. Q. Okay. If I add 10,000 and 12,000, I get 22,000? A. Yeah. I think the number I had quoted this morning -- Q. And you indicate here the 24,000 a year are going to be reaching this 35- to 40-year life expectancy, [Questioning] 979 Board Staff/Consultants so I mean, that's just ... A. Yeah, that's just-- Q. ... balancing the .... A. --balancing it, that is correct. At this point in time, I think that's the assumption we have made, that we will at least look at from a balancing point of view and then as we get into the condition of these poles again and see what the extent of the problem is, and we'll get some better information, and then we'll start addressing these programs in a different manner in future years. There is another category of pole replacement which is the southern yellow pine poles and the penta-poles. So if you take this program, plus the other program, plus southern yellow pine and penta-poles and the total of all that adds up to 23,000 plus. Q. Were those yellow pine poles and the penta-poles, I mean, what were their -- when you bought them, their life expectancy was the 35 to 40 years? A. That is correct. The southern yellow pine poles, they were bought like any other normal poles, but then, I think, we found some premature decay in those poles and certainly we started looking at that and we felt that there was a hazard, a safety hazard from a worker perspective because a lot of poles need to be climbed and we cannot access until we bucket-truck and certainly the decision was made that we will eliminate those poles from our system. [Questioning] 980 Board Staff/Consultants And penta-poles, we knew -- and what happened even in the January ice storm when we ran out of all pole supply, almost North America, then we had to put some penta-poles in the ice storm, knowing that we will go back and replace them because at that time the objective was restoration of power to the customers and whatever poles we could get, we did that. So we are looking at now from a penta-poles point of view replacement of all those poles in the sensitive location and -- but southern yellow pine poles, elimination of those poles from our system completely. But as you said, they were bought -- southern yellow pine poles were a surprise to us, but the penta which we even installed in our system as late as last year knowingly was done because we had no other poles available any place else. MS. LITT (Board Staff): Q. The southern yellow pine poles, is that the experience of other utilities that have installed that variety of wood pole? MR. D'ARCEY: A. Yes, it is. There was a decay problem that was consistent with southern yellow pine. It had to do with the treatment process at the time and so both Bell Canada and ourself and other utilities experienced the same types of problems. Q. Has there been any notion of going back to the manufacturer because the poles are decaying prematurely? A. I believe -- [Questioning] 981 Board Staff/Consultants Q. If there was an initial expectation, they would have an average life in the 30- to 40-year range. A. I'm not 100 per cent certain, but I believe that that was pursued and I don't believe that the company that originally sold them is in existence anymore. That's a similar -- it's not uncommon. It's a similar issue which we found with the two-piece insulators which also suffered premature failure and the Canadian subsidiaries are no longer in existence. Q. So there's no corporate entity to redress the issue? A. To the best of my knowledge. I'd have to defer that to our legal people, but I believe that was pursued. MR. HOPKINS: Q. Looking at the project for the deteriorated submarine cable replacement ... MR. HARDY: What page are you on? MR. HOPKINS: Page 93. Q. Is there -- well, maybe you could briefly just tell me the nature of this program, why this is needed? MR. ROGERS: A. We use submarine cable to service a number of islands mainly located in Georgian Bay or in the St. Lawrence River, Rainy River area. Submarine cable does not have the same life as overhead line, overhead line being 55 years and submarine Cable being 20 years. Also has the situation where you can't drive by and look at it and do a ready assessment. [Questioning] 982 Board Staff/Consultants The issue of an outage on a submarine cable is longer because of the fact that you have to -- first off, we don't work on water at night. So it has to be during the day and it has to be in weather that you would choose to go out in. So there are some difficulties around the customer side of when there is an interruption the length of the outage, as well as the fact that we can't -- the asset is indeed under water. We have a fair bit of cable that is above its depreciated life or the expected life. It is one program where actually the proposed amount that we are going to be doing under this program is more than actually what is depreciating at the time. So it's a recognition that this is an important program and one that we need to go forward with. Q. There is no way to tell by the performance of the cable that it's deteriorating, I take it? A. Yes, from the point of view that we tend to watch for cables that fail and when they fail you patch them and they fail again and after a certain number of failures over a time period, then you recognize that you've got a cable that's under stress and that it's time to remove it. Q. Do they fail when there is some resistance increase or something that would indicate deterioration? I just wondered if there were any technical tests that you are running to determine you need to replace it [Questioning] 983 Board Staff/Consultants or it's just because it's over 20 years it should be replaced? As a prudent practice? A. It is a prudent practice, but it is also based on the experience, the outage experience on that cable. Q. As we look at the replacement program for the deteriorated cable -- conductor, excuse me, indicated on page 103, it seems to indicate that here again we have a backlog of conductor in excess of the expected age of it and we're starting a program to remediate it. But clearly the levels of proposed remediation don't seem to build down the backlog of elderly cable, if you will, the 24 -- 28,000 kilometres of conductor that are in excess of 55 years as it is indicated here. I guess I was curious, well, about a number of things. Is there any scientific program being used to determine that it needs to be replaced other than you fully depreciated it, is one question? A. At this time with the situation that we have and the knowledge of existing conductor in the field that, indeed, is in bad shape and we found through maintenance we aren't doing specific sampling of conductor and sending it. It is a program, though, that will develop into that manner over time. The assessment in the field of cables would be based on the number of breakages, would be based on visual inspection of broken strands and if you went up and included the conductor cable where we were looking at No. [Questioning] 984 Board Staff/Consultants 6 and No. 4, again, those are cables that are -- conductors that are very small, that are becoming brittle, in fact are brittle, that you get anecdotal data when they are being pulled together to be tensioned after a breakage that they will break again. Those are conductors that need to be replaced at this time. Q. It seems like this program with 600 kilometres and 800 kilometres going forward is a fairly modest -- and not attempt to do that, and just sort of -- if you felt it necessary, strongly necessary to address this fairly significant distance of older cable this program clearly isn't going to help that much. A. Well, what the program will do for us is it will remove some specific conductors that we know are in problem and also give us an opportunity to put some techniques in place to do specific sampling and the like to better direct the programs. Q. Thank you. A. In fact, about 1700 kilometres of conductor throughout all of the different activities will be removed. So it's still short of the 2,380 that are aging sort of thing, but... Q. Okay. Looking at some of the sustaining capital programs, I want to turn to page -- the lines and station program that you have outlined on page 96 for a moment. This is kind of interesting because here we have sort of a lower cost than what you indicated the [Questioning] 985 Board Staff/Consultants historical was, 15.5-million a year or -- 15.2, excuse me, and you are proposing 11 and 9 going forward. Is there a reason for that? A. Other than it was based on what the needs were seen to be at the time when we put the program together, no. Q. When you work on feeders, how do you -- maybe you can describe a little bit how you select which ones you did and how you do that or... A. Certainly. We collect data on feeders that are in trouble, feeders that have significant numbers of customer outages, feeders that are identified as having significant percentage of poles that require replacement, the cross arms that have gone bad. We take a look at -- what we do is we collect this data from our forces on the field on candidate feeders to review and then we also take a look at the number of customers that are served off them and the length of time it would take to do repairs. And we take a look at situations of whether maintenance -- there are some maintenance activity that could take place rather than a capital activity. So we blend a lot of different things together and then set priorities and select the feeders that will be rebuilt. Q. This is using some of that reliability data that we talked about earlier that might be being kept in some fashions about outages and time duration and [Questioning] 986 Board Staff/Consultants frequency? A. Yes. I was one of those utility managers that people-- Q. Okay. A. --talked about in the past. You know -- the local staff know what lines are causing them trouble because they are the ones that they are out fixing at night at they are the ones where they are getting public pressure on. So even if there isn't a lot of written data around it, they have a very clear knowledge of which lines are in trouble. There are reports filed on each outage. Q. Going forward, that kind of information that local knowledge information will be somehow fed through our system, is that -- there's provision for that as well as other data? MR. SURI: A. That's correct. Q. Outages would be identified by circuits or something of that nature-- A. Absolutely. Q. --giving you an opportunity to review that? A. Absolutely correct, because the system I think -- that's where the system can also help us from asset management point of view and investment planning point of view also, that what kind of replacement programs we should be getting into because we will start getting the outage data on a central basis. We will start getting the maintenance record on [Questioning] 987 Board Staff/Consultants the facilities and we can develop some correlationships and then really come up with programs and priorities on a provincial basis. That's exactly what's lacking at this point. Q. When you look at it -- you mentioned that capital, you know you might do maintenance or you might replace it and you make decision on that basis. Are there some rules on how that is done? MR. ROGERS: A. There are a variety of different things that you look at and you do a benefit analysis and you take a look at whether doing maintenance is going to have a longer term effect or whether it's going to be short-term. You take a look at whether this is an opportunity to relocate the line to another location so that maintenance costs into the future will be less, reliability will be higher, response time, if there were outages, is going to be better. So you look at lot of different things when you are making the decision on which way to go. Q. Well, is there some data you are using that would say a new line with the expected frequency of outage, it would be "x" and an old line, you know, you have your historical number for this that you would be able to use that in some analytic form in your analysis? And is it an economic tradeoff analysis of doing maintenance, just going back and fixing the line or replacing it? [Questioning] 988 Board Staff/Consultants And I guess is it a program "d'affair" that you use to do this in some fashion? Do you have a computer model that helps you with this any fashion? A. I can't answer whether it's a computer model or not because I'm not aware. But, yes, it is a financial tradeoff. Q. I see. I've seen some models that do this from some other companies or reportedly do this through the life analysis, and I didn't know whether you were using, but this would be a life cycle analysis and it would consider savings from improvement and losses I presume as well as outages and things of that sort? MR. SURI: A. We are at the moment introducing reliability centered maintenance kind of an approach on the distribution side when we start looking at all this information on a collective basis. So the idea would be is that the maintenance cycles also can be looked at from a reliability perspective and what kind of reliability levels are we going to be probably shooting for in developing the programs. When we are looking at that, combine that with the objective of minimizing the life cycle cost of the assets which will result in the decisions whether we need to get into replacement or you need to go into maintenance. Those kinds of approaches are currently being developed and currently being reviewed. That's the work [Questioning] 989 Board Staff/Consultants which has started, but we're not there as yet. Q. Just on another subject or maybe a related subject. When relating to storm damage and what have you you mentioned you have some provision for storm damage. Is that -- that is inherent in the budgets we are looking at? In some fashion, is there an accrual for storm damage account inherent in what we are looking at or is it part of each of these programs or not included? MR. ROGERS: A. It is a specific item. Q. It is, okay. A. The $3-million for -- Q. Three million a year. I may have missed it. A. When we talked earlier I mentioned that there was a form that was coming across. We will make sure of that. Q. It is in one of these programs here? It would be sort of a capital amount to be set aside for a reserve fund which, I take it, is fairly well depleted at the moment? MR. SURI: A. It would be in the sustaining capital lines and stations category. That's where the storm damage monies are accounted for. Q. Just bear with me for a second and I will see what... MR. HARDY: I wonder if I can just poll the participants again. Any other participant questions? ---(No response) [Questioning] 990 Board Staff/Consultants MR. HOPKINS: In a sense -- we're just trying to decide who is going to ask who the question. Q. I notice in the development capital program for LV feeders and distribution substations and rural feeders which is the capability enforcement program, page 106, you indicate that looking at load increases of 1 per cent per annum: '...Forecast volumes of worker based upon expectations requiring for 1 per cent...' Is that consistent with your overall forecast? I don't believe it is. MR. URBAN: A. Yes, I think we discussed this in a related question this morning. The 1 per cent represents our best estimate of new local capacity requirement, the total new local capacity requirement, relative to the total demand on the system. Translates into roughly 40 megawatts of new local capacity. It's very difficult to relate that to the total system because at the same time the total system demand could be declining because we're attempting to fix the micro capacity demand gaps all over the system. The reason we use that number is because the programs for the year aren't defined fully until probably March of the year because we have to have gone through the winter peak, but we want to be able to establish the total amount beforehand based on some parameter. So it is our best guess. We arrive at that number based really on judgment and look at the overall -- [Questioning] 991 Board Staff/Consultants things I spoke about this morning, what's happening overall in the province. Q. We have no, and hopefully we will have some reference of history, you know, to reflect on in this area as well because it sounds like it is quite judgmental as to whether or not this kind of expenditure will be needed. A. The way the money is actually spent isn't based on the forecast. It's based on an analysis of the individual situations and the money is only spent if, in fact, we have an overloaded facility. So the history is based on remediation of overloaded facilities. The projection is only there to help, you know, put the situation in perspective. Q. Okay. Thank you. I appreciate that. Let's see if we can deal with some other programs than -- other items rather than just the capital programs for a minute. Included in the rate base we have an element for working capital. Has Ontario Hydro previously considered working capital as part of its requirements and is this type of an analysis for the amount required what you typically would use? MR. HARDY: Is there a reference? MR. HOPKINS: I want to get the reference. I just lost it. Somebody says 79. In the December 7th filing. MS. FRANK: On page 79, table 1, it talks about current and other assets which is a portion of working [Questioning] 992 Board Staff/Consultants capital, but we need likely table 7.2 on page 82 to get the rest of the way there. MR. HOPKINS: Q. You are asking for the allowance to be the difference in these, is that my understanding? MS. FRANK: A. Yes. Another alternative reference would have been on page 45 where we had the rate base and we show on line 8 of table 7-1 the net receivables and other assets. That likely comes closest to what we filed on working capital. Q. Right, and that's driven in the difference between current assets and liabilities or ...? A. The mid year of the difference, yes. Q. The mid year of the difference. Is that the way Ontario Hydro has traditionally looked at its working capital requirements or is it something new to Ontario Hydro or ...? A. We've traditionally looked at it by element, so we've looked at the current assets and other assets and, you know, and current liabilities all separately. The presentation of it as to a mid year net receivables and other assets as is done on page 45 is likely new, but the levels of each one of the elements, it would have been typically done as we would look at our planning period in coming up with a proposed plan. Q. In many jurisdictions where we've had regulated utility activity and allowances made for working capital typically, there's a performance of something [Questioning] 993 Board Staff/Consultants called a lead lag study of costs and revenues and expenditures. Is that something Ontario Hydro has ever performed or ...? A. I think we made mention in our submission actually that we typically didn't do lead lag studies and we haven't done that at this time. Q. I don't know what to make typically, I guess, whether or not there was -- that was something you only did once three or four years ago or never ever? A. No, we don't. Q. Never ever. A. We haven't done lead-lag studies. MS. LITT: What did you do in its place? MS. FRANK: We would have looked at the, I'd say, basic drivers of each of the key elements under this, so, you know, what's in current assets, what are in the current liabilities and identified each one of the elements and what our forecast is for how that element might change over time, but we didn't do studies on actual experience. MS. LITT: Okay. MR. HOPKINS: Q. I think, you know, consistently with other utilities you may be asked to do one of these lead-lag studies sometime to justify ... MS. FRANK: A. Yes, I'm aware that that may well be a requirement. Q. With distribution capital projects, are these [Questioning] 994 Board Staff/Consultants -- these are all typically done within a year or something like that. I mean, these are short life projects and you don't capitalize funds for AFUDC, do you, on these projects? A. We do capitalize allowance for funds used during construction for anything -- any asset that has several -- even months over which it would occur. The amount that's capitalized is naturally very small because most projects from start to end is a relatively short period, so the basic principle is still utilized, but the absolute dollars are very small. Q. Let's turn to -- on page 80 of the same December 7th filing. You have your deferred pension asset discussed and the amount of it being 120-million. How is that amount determined? A. This was an actuarial evaluation of the obligations that we would have under the pension versus what the value of the pension is. Q. Provided to you by an actuarial firm, a study or some sort, was it? A. We would have used an external firm to do it, yes. Q. And that's divided into transmission, distribution and other functions? A. Since the pension fund at the moment is an Ontario Hydro pension fund, yes, it would have been divided on the basis of the number of employees in each of the companies. [Questioning] 995 Board Staff/Consultants Q. Not the payroll? A. I think -- well, actually employees and likely past employees as well because it's a pension obligation, so they had to figure out what the obligation was for each company, not just current employees. Q. Your pension obligation would, of course, vary by the number of people affected, but it would also vary by the payroll, would it not, typically-- A. Yes -- Q. --the higher pay, the higher pension? A. As you can tell obviously, Bill, this is not one of the areas that I manage, but yeah, I imagine there is some salary implication as well. Q. In your chart of accounts, what liability offsets this asset or -- I mean, is that what we're ...? A. This asset is -- actually, relatively recently GAAP suggested that any amount of pension that the value is over the obligation can be recorded on your books as an asset, so this is an asset. It's the difference between what our obligation is and what the value of our assets are, so there's not a corresponding liability to that difference. Q. A negative asset, is that what -- or, no? A. No. This is a positive asset. Q. A positive asset .... A. The value of our pension holdings is greater than our obligation. The difference is what we've got booked, not the total amount. [Questioning] 996 Board Staff/Consultants Q. Where do the earnings from that go? A. I'm sorry, help me. What earnings? Q. If you have an asset that is in excess of the liability and this pension pool is -- has some set-aside funds, all right, they earn something every year - 4 per cent, 8 per cent? A. They go back into the pension. Q. Just accumulating even though it's surplus as well. A. Yes, they're accumulating. We don't add to them because we're not -- during this period -- now that we have a surplus, recent changes to regulation allows no longer to add by actually -- you know, we don't have an expense in here for our contributing to the pension fund. The pension obligation increases for every year of service that people add to it. The only increment that the company is making is what we earn on the asset. We're not actually having an expense; whereas in the past, one of our costs would have been contributions to the employee pension plan. We no longer have contributions to the employee's pension plan because we have the surplus asset. Q. Is there an expectation that this surplus will diminish going forward and is that sort of like the, I guess, President last night, that in the year 2032 we're going to run out of money and social security in the U.S. or something of that nature, but I mean, is there a projected D-day for this or ...? [Questioning] 997 Board Staff/Consultants A. We expect that the surplus will last us about ten years. Q. Ten years. So it's prudent to add back the earnings to it; it's not a permanent level of surplus? A. No, it's not. It will need to be revalued on an annual basis to determine what the value of the pension holdings are at any point in time and also the actuarial obligation that we would have. But our current estimate is that by the end of ten years with the company not making any contributions, we will be at a point where we'll have to -- we'll have used this up and we'll have to resume making contributions. Q. Thank you. Turning the page, we have OPEBs, O-P-E-B assets, other post-employment benefits. How are these -- how is this determined, OPEB liability of $200-million or so -- 236-million? A. The other post-employment benefits is the obligation to retired employees or their spouses for things like group life insurance and health benefits, so they already know the population relatively well and we know what we've under our contracts agreed to provide them so we can certainly come up with what the cost is going to be for this. And we used to treat it on a pay-as-you-go basis; as we make the payment to the retirees or their spouses, we'd incur the expense and we've moved over to an accrual basis and that's why you now see a liability and an offsetting asset. Q. In deciding the amount of the liability, [Questioning] 998 Board Staff/Consultants someone did, you know, an analysis for you, an actuarial as well as, you know, what the funding level would need to be to meet those payments in the future and earnings on the funding and all that; there was an underlying actuarial analysis made for this? A. That's correct. Q. And is that -- again we have that for the Ontario Hydro and then we've allocated it; is that the concept here again? A. Yes, it is again. Q. And it's again on the number of employees you think or ...? A. I believe certainly numbers is a key factor in this allocation. Q. This one might be closer to that I would think. A. I think so because I don't know that there's much differentiation in benefits. There may be some slight differentiation by contract group. Q. How often is that study of the liability done? I mean, the number that's shown here was done - last year, this year, two years ago? A. This is new because prior to January 1 of 1997, we didn't do this, so ... we just made a relatively -- January of '97 we made the accrual and I believe we'll do annual assessments on that as well. Q. Have that looked at annually. Thank you. I'll turn to a topic or two on cost allocation, [Questioning] 999 Board Staff/Consultants Appendix G in the December 7th ... December 23rd, excuse me, document, which is .... I may have the wrong reference, so give me a moment. We don't have G, huh? Ah, Appendix G of the December 23rd supplemental filing, page 17. Here we're describing the asset management share of the overhead -- or the shared functions from Ontario Hydro Services Corporation and allocated on a 65 per cent to transmission and 35 per cent to distribution basis. It mentions that these allocations are derived by comparing the total O&M and capital costs of the two related business units excluding property taxes. It says that because property taxes are significantly occurred in the transmission business and require little supporting cost and that this would distort the comparison if you included it. But I guess the issue I'd have is, are there other items that are similar to that that might also be considered to be excluded? For instance - I have a suggestion - you're including the capital cost in that, you know, that are going forward in the year, but those are really made in some prior year decision process so they're not controllable, if you will, are they? A. Well, what this is saying is, actually, the cash that's spent during the year is-- Q. Represented by those two -- A. --what we're using as the basis on which to do the allocation and the idea is, the cash that's spent during the year is requiring our people to work, to spend [Questioning] 1000 Board Staff/Consultants the money, and all work requires some support to get the work done, so if that be from the human resources supporting our people, if it's from the finance systems supporting the numbers. It's really the dollars that are spent in the year that drive a lot of these other support activities to be occurring, so that's why it was total dollars that got looked at. And the taking out of the tax was -- it was a very large single amount that really didn't require much support. It didn't require HR supporting people to pay the tax. It didn't require finance to do a whole lot of work with one big large cheque that was pretty simple. And when we go to any of the other support items that are in there, regulatory performance management, they really look at total expenditures. All OM&A and all capital seems to be a relatively good driver for why the support is provided. Q. OM&A would then not include such things as income tax or anything? A. No, it does not. Q. But it would include property tax if we -- A. No. We took it out. We took the property tax out. Q. But it would otherwise include it -- A. Yes, it would otherwise. Q. Thank you. Just backing up a little bit and looking at the drivers that you used as well, in the allocation on pages 11 and 12 of that document, you [Questioning] 1001 Board Staff/Consultants discuss sort of general drivers and you state that the general drivers used by other companies often compare assets or salaries to show the relative size and complexity of things of the organization units, but you selected net asset book values for the general -- as the general driver. What if you had selected salaries or wasn't that a choice or ...? A. Salaries -- actually, labour costs, would be my characterization, were used where labour was seen as the appropriate driver, so -- Q. It wasn't one or the other; it was both? A. I'm trying to see, if you'd give me a moment. I think in the original submission -- Q. Over on page 12 it sort of suggests that, you know, to reflect the general size and complexity of these business units, the general driver has been calculated using a business unit's proportionate share of the total net asset book values. That was lines 4 through 6.. MR. HARDY: If I could just hold this. Just give Susan time to refer to the original document. MS. FRANK: I'm trying to find it. I think -- we'll carry on with page 12 and use that. But where we had no other driver that was really helpful because it seemed to be an item, a cost factor that we couldn't specifically assign to a more specific driver, we used the general driver. But if you looked on page 12, you'll see that we [Questioning] 1002 Board Staff/Consultants used several specific drivers and sometimes historical accidents, if it was a health and safety type of cost, that would be a good driver, sometimes - on to page 13 - accounts payable because really what the cost was, was processing of accounts payable, so we would have used the actual accounts payable records. And if I go on to page 14, we get into staff numbers rather than dollars here, Bill, but, yes, where it is labour that's the driver, we have a specific driver associated with staff and then I just picked a few out of that. Only the items where we didn't have a good specific driver did we say, well, then let's use net present value because that's the general driver we'll use in the absence of a specific item that we could point to. MR. HOPKINS: Q. But you don't think you could have as easily said let's use the labour ratios, you know, representing? And I guess my question is: Would that have made much difference? You didn't try different drivers. You just sort of -- MS. FRANK: A. Well, we thought that likely labour -- I think that's that first comment that you read to me about drivers that relate to comparative size and complexity of the business and I think it's the complexity of the business side of it where we felt labour likely wasn't as good an indicator of complexity of the business. A lot of the decisions that are necessary on the assets were driving a fair amount of the support costs but don't [Questioning] 1003 Board Staff/Consultants have a lot of people involved in making those decisions. So in terms of complexity and where support is needed, more of it seems to go on the basis of the assets rather than the people. The other thing I would like to point you to is on page 16 which is a table in that same filing. It actually tells you what the work program was and the second column tells you what driver we used. So that's this rather unwieldy table. Q. Well, there is quite a few that have been taken up on the -- the general driver, when it says general driver it means net asset value-- A. Yes. Q. --as well? A. Right. Q. That's the same as NVV assets, the indication as well? A. Yes, it is. Q. So there is quite a bit on NVV assets and there is very little on salary unless staff numbers represent salary. Is that... A. I don't know. If I look at staff numbers I see quite a bit on that first block of items that are being allocated and I'm just going to look across at the numbers and in total -- Q. Are those numbers like 104 and 103 people or are those -- A. The numbers under the "total" column, is that [Questioning] 1004 Board Staff/Consultants what you're asking? Q. The driver that you'd call allocation factor staff number, that's not salary. That's the number of people? A. Yes, it is the number of people. Q. So the idea that there was -- general drivers often compare assets or salaries which was the statement made back on page 11. When we come over here and we look for, okay, assets or salaries, I don't see any salaries at all. A. No, I'd said we picked the asset value. We felt it was more reflective for us. But on the specific drivers, we do have staff numbers sometimes and I'm showing you the ones where we used staff numbers. When you look at the total dollars that are allocated on the basis of staff numbers, there are some big dollars in there that are allocated on the basis of staff numbers. Q. Yes. I guess I'm not making it plain. Two people, Anne and myself, are two people but our salary will be different than you over there. A. If you're saying if you had a choice on your general driver it could have been salary and it could have been net book value -- Q. Or it can have been number of people, right? A. Well, number of people we didn't consider as a general driver. What we considered really was the salary and the net book value and we decided net book [Questioning] 1005 Board Staff/Consultants value was better for our business than salary. Q. I'm wondering -- MR. HARDY: I guess I'm hearing double questions... MR. HOPKINS: Q. I think I've got what you're saying finally, that the choice on the general driver was those two and where it says "general driver" it is just one of them? MS. FRANK: A. Right. MR. HOPKINS: Right. Okey-dokey. MR. HARDY: Can I get a sense of how long you are going to continue? MS. BULKLEY: Two more questions. MR. HARDY: Pardon me? MS. BULKLEY: Two more. MR. HARDY: Two more questions. Okay. MS. LITT: Q. Looking forward, do you see yourselves continuing to use net book value as the driver or would some refinement or totally different driver be proposed? MS. FRANK: A. We're quite hopeful that when we come back next time we will have a better and more precise method of allocating these costs and not be into -- our preference would be not to have to use general drivers. I don't know if we'll be that far next time or if it's a directional thing, that we are going to try to reduce the use of a general driver and I don't know what it might be next time. [Questioning] 1006 Board Staff/Consultants MS. BULKLEY: Q. You actually referenced page 14 in this discussion. If I could just direct your attention to the asset owner cost driver. Can you just give me a sense of how this is forecast? How this is... MS. FRANK: A. I'm sorry, I'm going to have to refresh my memory on this one. I don't. Q. Okay. Is that something that maybe you could tell me tomorrow or something? A. The question is how it's forecast? Q. Yes. A. Okay. Q. Sort of the follow-up to that also is after the Y2K issue is resolved, does this -- will this no longer be used? A. I'm not clear on that question, I'm sorry. Are you talking about the asset owner if -- once Y2K is resolved will we not have asset owners? Is that the question? Q. This cost driver, yes. A. I'm having trouble with the relationship. Q. Isn't this only used in Y2K costs? Maybe I'm confused. MR. HARDY: Can you just refer us to where you are. MS. FRANK: I see what you're doing. No, there is a difference there. Asset owner is the driver. I'm going to have to tell you how we forecast [Questioning] 1007 Board Staff/Consultants asset owner. MS. BULKLEY: Q. Maybe that will be helpful. Maybe I should just -- MS. FRANK: A. The Y2K is a cost that was allocated on that basis. There could have been other costs that were allocated on that basis. That's the only one we happened to have used. MS. BULKLEY: Okay. MR. HOPKINS: Q. One of the corporate functions that -- I think somebody asked this once before, but I want to take you back to page 8 under "Corporate Affairs". It mentions -- it probably is the first function of the corporate affairs group is going to be to establish an Ontario Hydro service corporation brand and brand reputation. What does this sort of activity involve and how is it related to the regulated business here? MS. FRANK: A. I think what's described here is all of the overhead costs for all functions that aren't directly involved in the transmission or distribution work, but I believe that when Don Ariss was discussing this material with you on panel 1 he indicated that some of the costs were actually removed because they indeed are not strictly regulated business activities. I would like to confirm that, but I believe this activity would be of that nature. Q. Okay, that's fine. I have another question on your working capital, I guess. How did you get those [Questioning] 1008 Board Staff/Consultants mid-year values for your receivables and other assets? Is that -- that were shown on that schedule? A. Very mechanical and simple exercise. Start the year, end of the year, divide by two. MS. BULKLEY: That's clear. MR. HOPKINS: Q. I think I'm down to my last question. I have a question on the construction work in progress, but I will ask you it tomorrow because you are going to be here, right? MS. FRANK: A. Yes. MS. BULKLEY: We need to -- the page reference is inaccurate here so we need to clarify that. MS. FRANK: That sounds fine. MR. HOPKINS: I don't want to hold you up while I fumble looking for it. MR. HARDY: Does that complete your questions? MS. LITT: I would like to ask one more question. MR. HARDY: Go ahead. MS. LITT: Q. For all the dollar amounts that are set out in the evidence in the filing, are those nominal dollars or real dollars? MS. FRANK: A. Dollars of the year. MS. LITT: Thank you. MR. HARDY: Okay, thank you. Are there any additional questions from participants before we start to tie things up? Bill, do you have something to add? 1009 MR. HARPER: If all the questions are done, I would just like to follow up on a question Bruce raised at the end of yesterday's session with respect to information forthcoming on the revenues generated by our current retail rates and I'll put some material on the side that people can pick up when they leave, addressing that. MR. HARDY: Thank you. I don't see any other people who have questions to ask. Everybody has asked the questions that they are interested in asking today? ---(No response) That's fine. Panel, is there any other additional information you wish to provide? ---(No response) Thank you very much for all your hard work throughout the day and thank you, participants, and Board Staff and Consultants. We are adjourned. ---Whereupon, the Technical Conference proceedings were adjourned at 4:53 p.m., to be reconvened on Thursday, January 21, 1999, at 9:00 a.m. 1010 I N D E X o f P R O C E E D I N G S Page No. Overview (Facilitator) 800-801 Introduction of SERVCO panel 801-802 PRESENTATION by Vipin Suri 803-833 Introduction of Board Staff and Consultants 834 QUESTIONING: by Board Staff and Consultants 834-865 by Participants 865-896 ---[Lucheon 12:05 p.m. - 1:10 p.m.] 896 by Participants (cont'd) 897-934 by Board Staff and Consultants 935-970 by Participants 971-974 by Board Staff and Consultants 974-1008 Parties who questioned: R. White . . . . . . . . . . ECMI B. Bacon E. Robertson . . . . . . . . . OCAP R. Stephenson . . . . . . . . Power Workers' Union J. Fisher K. Snelson . . . . . . . . . AMPCO R. Scully S. Walker . . . . . . . . . . ECNG K. Bryan . . . . . . . . . . . Union Gas Limited JB/MC [ Copyright 1985].