RP-1998-001 THE ONTARIO ENERGY BOARD Ontario Hydro Services Company Inc. (SERVCO) Interim Transmission and Interim Distribution Applications Hearing held at 2300 Yonge Street, 25th Floor, Hearing Room No. 2, Toronto, Ontario on Tuesday, January 19, 1999 commencing at 9:03 a.m. --------------------- TECHNICAL CONFERENCE "Transmission Cost Allocation and Rates" VOLUME 6 --------------------- F A C I L I T A T O R : DAVID HARDY Board Technical Staff 680 A P P E A R A N C E S DAVID HARDY ) Board Technical Staff KIRSTEN WALLI ) BRIAN HEWSON ) in conjunction with: SUSAN SIMMONS ) Reed Consulting ANN BULKLEY ) Ontario Hydro DAVID CURTIS ) Services Company Inc. ANDY PORAY ) [SERVCO] 681 ---Upon commencing at 9:03 a.m. MR. HARDY: Good morning. Why don't we get going? I'm Dave Hardy. I've been asked to facilitate the continuing rate order sessions. Is there anybody here who has not attended a previous session? ---(No response). That's fine. So I'll keep my opening remarks fairly brief then. We do have -- been collecting, yes, questions that have been coming up throughout the sessions that we're going to have responses from SERVCO and we will be starting this morning with some responses to some questions that were posed in earlier sessions and then we'll be moving on to the issues relevant to transmission cost allocation and rates. At that point, I'll have the panel introduce themselves. I think we'll keep with the format of also having Board Staff and Consultants pose their questions and then open up the questions to participants. With that, why don't we move to have this panel introduce themselves, reintroduce himself in one instance, and then, David, you can lead with some responses to some earlier questions that would be appropriate. So why don't you go ahead? MR. CURTIS: Good morning. My name is David Curtis and I'm the Manager of Transmission Regulation for Response to Yesterday's 682 Questions by SERVCO Panel OHSC. MR. PORAY: Good morning. My name is Andy Poray and I'm the Manager of Pricing and Product Development for OHSC Transmission. MR. CURTIS: And I thought that I would lead off this morning. I read over the transcript from yesterday's Technical panel and noted that there are a few areas of questions that were posed and I thought that I hopefully will be helpful this morning in terms of providing a response. RESPONSE TO YESTERDAY'S QUESTIONS: MR. CURTIS: The first area of questioning was from Bruce Bacon of OCAP of why in OHSC's comments regarding the OEB staff report PB options for electricity distribution in Ontario that is contained in appendix 4 of the distribution application, why we believe a price cap form of PBR should be applied to distribution. Yesterday I said this question could be posed to the distribution panel; however, since PBR is not part of the current rate order application for distribution to the OEB, there won't be anybody on those panels in a position to address this question, so I thought that I would comment that we were suggesting the adoption of a price cap for distribution for three reasons. The first is, price cap is the most relevant of the regulation alternatives in the OEB staff report to residential and commercial customers that make up most of the distribution customer base since it links directly to Response to Yesterday's 683 Questions by SERVCO Panel the prices that they pay. The second one is that price cap links more directly to distribution's cost drivers than does revenue cap; that is, the number of customers in the case of fixed costs and the energy use in the case of variable cost such as losses. The distribution utility is incented through price cap to control losses through design standards and system upgrades and costs vary more directly with the number of costs -- sorry, with the number of customers and energy than they do for transmission. And the final point for price cap is that it would offer customers more stability on price. Now, the process established by the OEB for examining PBR for distribution we feel is the more appropriate form for discussing our ideas on distribution. The second question was posed by Richard Stephenson of the Power Workers' Union and I'd like to respond to whether or not OHSC would abandon the asset management model if PBR for transmission was deferred for this rate order application. The answer to this is no. OHSC is making a distribution rate order without PBR and yet the asset management model is also being applied within OHSC's distribution business and the asset -- sorry, and the asset management model has been developed within OHSC with only the expectation of PBR. OHSC would not abandon the asset management model if the introduction of PBR was referred; however, as I presented yesterday, PBR and the asset management model are natural allies Response to Yesterday's 684 Questions by SERVCO Panel with PBR providing the external driver to support and sustain the internal drivers developed under the asset management model. And the final point was a series of questions around whether or not we had had our PBR proposal reviewed by external parties and if we could offer an opinion on -- their opinion on that and my response yesterday was that we had discussed with external consultants, but their response was in a verbal form. What I would like to offer up which hopefully will be helpful is a working document that we have given to our external consultants and they had helped in terms of its development and we would make that available to the participants in this hearing. MR. HARDY: Thank you, David. There may be follow-up questions based on the response David has provided, if you could hold those questions and we'll hear Andy's presentation and then we'll ask them at an appropriate time. Andy, would you like to begin with your presentation? MR. PORAY: Yes. Thank you, David. PRESENTATION BY MR. PORAY: Once again, good morning, ladies and gentlemen. It's nice to be here and it's nice to see that -- I would say a fair proportion of you were involved in one way or another at the market design committee. So those of you who have heard the stuff are free to leave if you don't want to hear it again. Presentation 685 (A. Poray - SERVCO) I've asked David to present the slides -- or at least to put the slides on the overhead projector and let's hope this dynamic duo will work. Before we get into the cost allocation and the rate design, I'd like to just perhaps put up this overhead 'Why do we need a rate order now?' I think this question has been raised throughout a number of the panels and it was certainly answered in all of the panels, but perhaps just to cap it together, we really need a rate order now because under the statute, OHSC needs regulatory approval for it to complete the relevant credit ratings and fund rating processes. As a company that's going to be involved in the marketplace, as a participant in the marketplace providing transmission facilities to the market users, we need to really develop a rate ahead of time, ahead of opening up of the market so that the market participants have some idea of what these rates are going to look like. They can make some preliminary decisions in terms of costs that they will incur by using the transmission system. And synonymous with the market design committee which is really developing the market rules which will come into effect on the opening of the market, this seems the right thing to do. In addition, any future importers or exporters can plan for open access and apply for any FERC licenses that they may require and FERC may require to see a transmission rate. Presentation 686 (A. Poray - SERVCO) Okay, so if you now would like to turn to our main presentation. What I'd like to do today is really to take you through the process that we followed in doing the cost allocation for transmission revenue requirement and the rate design which are summarized in chapters 11 and 12 of our submission to the OEB. And in this context, I'd like to follow through these main areas. I'd like to talk about the transmission system and how the assets are unbundled into the connection and network categories, how we allocate the transmission revenue requirement components to the separate categories of assets, what is the basis for our rate design and what are the resultant rates. And I'd like to perhaps just close off at the end to talk a little bit about how transmission might be -- transmission service might be offered during the interim period. So starting off, let's now look at how we categorize the transmission system and the associated assets. What this diagram indicates is the connectivity of the customers, the transmission customers, and the transmission customers have been -- well, the concept of transmission customers has been described at other panels and essentially, transmission customers are those entities who are directly connected or physically connected to the transmission system, so it will be the generators, it will be the direct consumers of electricity, the large industrial customers, and the local distribution companies or the municipal electrical utilities which are directly Presentation 687 (A. Poray - SERVCO) connected to the system. Although these various entities have different electricity requirements, they are all transmission customers. They make use of the transmission system in one form or another. Now, looking at that diagram, you can see that there are some facilities, some transmission facilities, which may be directly assignable to customers and typically these would be the radial lines and radial transformation facilities which connect the customer which can be identified with a specific customer that connect them to the system. So for the generator on the left-hand side, there's a line that connects it to the system. You could say that this is a connection facility and it performs that function. For the industrial customers, there are connection facilities that connect them to the system and so on and so forth. The rest of the network, it really is a mesh. It's a combination of lines and stations which are interconnected in such a manner to allow for the transfer of bulk electricity from fuel generating sites located in specific places in the province to many load distribution centres located throughout the province and the ability of the transmission system to handle the flows through a variety of paths allows for a reliable system and for reliable delivery of electricity. You could really visualize the network as the 400 Presentation 688 (A. Poray - SERVCO) Highway system in southern Ontario which really carries a lot of the bulk traffic in between, let's say, from Detroit through to Montreal and up north towards Sudbury and the radial facilities as the municipal roadways that connect the various users to the highway system and allow them access to that system. Now, the criteria which we use for segregating our transmission assets into the connection and network are covered in the next overhead. David? One point perhaps if I could go back to that slide, you will notice that we've drawn a map of Canada and the U.S. and these are interconnection facilities. These are the facilities which allow us to interconnect with neighbouring jurisdictions and we've utilized those facilities for purchasing power from outside entities as well as selling power to outside entities. Okay. In terms of the criteria that we used, I think one of the main aspects is we want to move towards cost causality and the provision of appropriate service and we feel that a connection service and network service are really two separate services. We have used what's called the mothball test to really functionally categorize the facilities. And what I mean by the mothball test, essentially we take the system, we look at all the connection points on the system, the customers that are connected at those connection points and we remove each customer. We mothball them. We look at what happens to the power flows on those facilities. If the power flow Presentation 689 (A. Poray - SERVCO) goes down to zero, then essentially you could say that that customer is the main beneficiary of that particular facility, so that's a connection facility. If the power flow changes direction or increases or reduces, it really is part and parcel of the common grid that's used by all customers. There's an historical perspective that we followed and that is that there has been a bundled -- the transmission system has been bundled, but we have effectively unbundled the transformation to take care of those entities today that own their transformation facility so that they're not double charged. There's consistency with our approach with the way the account design committee has been going and also there's consistency in the way the other jurisdictions in the United States and elsewhere in the world have been going. Before we get on to the next slide, I would just like to talk a little bit about the radial line facilities. The transformation facilities that connect customers to the transmission system are fairly well. One can visualize these as being radial and supplying a customer. Radial lines is a bit of an awkward beast in the sense that there may be not only one customer, but groups of customers that were served from the same line. The lines themselves might be used or switched either in a radial mode or connected back into the network to help alleviate local problems. And in the Presentation 690 (A. Poray - SERVCO) past, a lot of the lines that were there are radial lines were, in fact, part of the network, the overall transmission network. So the question of lines is not as clear cut in a lot of cases in terms of trying to identify which are the radial specific, radial line facilities. For the purpose of our submission, we have included the generation lines and the customer lines into the common network pool. We felt that this is our first crack at unbundling the transmission costs and the transmission assets. We've still got some ways to go, but this a good start. So let's, having separated these assets into the connection category and into the network category, what do these look like in terms of the net book value and this line gives you some idea of what that is. So about 21 per cent of our -- 20 per cent of our assets are used for connection and the bulk of our assets are really used as network assets. And this is really quite consistent with the type of business that we are in. We are in the business of transmission. We are in the business to allow power to flow from large generating, centrally-located generating stations, to many load centers scattered throughout the province, and that is how the transmission system performs its function. Having separated these assets into the two categories, the issue now is: How should we allocate the cost? This is really where the fun begins. Should we use Presentation 691 (A. Poray - SERVCO) pooling, should we use specific cost allocation? And these next two slides deal with that. Essentially in pooling, we feel that this allows for a gradual movement from where we are today. The customers -- the customers today pay a bundled rate and transmission is pooled in that rate. It's a fair way of allocating the recovery of some costs from existing customers. Those customers are there, those facilities were built specifically for those customers, to benefit those customers, and they should have the responsibility for recovering this on costs. A pooling approach is fairly easy to understand and is fairly straightforward to administer. It is our understanding and it is consistent with the government's "White Paper" in terms of trying to establish a uniform transmission rate across the province, and it's certainly consistent with the Market Design Committee recommendations which have also gone in the same direction. Turning now to specific costing. Specific costing is cost reflected -- it does allow for cost- reflected pricing. It does tend to remove cross subsidies, but it may discriminate against some existing customers for whom these facilities were built on an integrated, vertically-integrated utility basis. And the main issues could be around the historical decisions based on, as I say, on an integrated utility and the facility vintage and facility utilization. And going toward Presentation 692 (A. Poray - SERVCO) specific costing for the recovery of existing costs appears to be contrary to government direction and MDC recommendations. So we feel that the pooling approach is perhaps the best way to go or at least the best way to start into the new era of unbundled transmission rates. And so we would create a cost pool for the transformation facilities which would just contain all of the costs associated and provided with the transmission, with the radial transformation. And then the remainder of the costs which are referred to and which pertain to the network would be contained within the network pool and that's indicated in there. Those costs would be associated with providing the meshed infrastructure, the lines and stations connecting generators, the radial load customer lines, and the interconnection facilities. So what we've done now is we've created two pools, two cost pools, the connection cost pool and the network cost pool, and now how do we go from here towards -- in terms of allocating the cost components of the revenue requirement to those cost pools? Now, this slide shows the transmission revenue requirement in the left-hand column, the totals are to be found on page 68 of our filing. And the right-hand column indicates the allocation method that we adopted. And the reason why you see a variety of allocators there is that not all costs can be allocated in the same manner. Presentation 693 (A. Poray - SERVCO) One of the first things I would like to do is to clarify perhaps what some might think is an anomaly in our appendix queue pertaining to the OM&A total figure. You will see in this slide that we show a value of 440-million as being the OM&A; whereas, on page 68 of the filing, the actual number is 441-million. When we were doing this exercise of cost allocation, we weren't sure, we had no direction how the transmission performance incentives and the capital taxes should be allocated to the various cost components and therefore we put them in the OM&A bracket. So what we did is we took 441-million, we subtracted the recoverable work which was 67-million, and we added 23-million for the transmission performance incentive and 17-million for capital taxes and that is how we obtained the 414-million. Now, if we can just put aside for the time being the allocation of the OM&A costs and just focus on the other components. The depreciation, we allocated based on depreciation costs which are asset specific, so once we have categorized which asset belonged to which book, it is fairly straightforward to go into the data base and find what depreciation is associated with which assets. The other cost elements, the interest, net income and income taxes are not asset specific, they are really a total revenue requirement or based on the total revenue requirement. And we allocated those on the basis of ratio net book value. Returning to OM&A, as noted before, we included Presentation 694 (A. Poray - SERVCO) the transmission performance incentive and the capital tax and excluded the recoverable work to obtain the total that we show here. The allocation of the OM&A component is somewhat challenging and the unbundling process within the Ontario Hydro Services Company has not yet reached that level of detail which allows us to specifically allocate or determine what costs were incurred with which assets. And therefore we have to use some proxy for allocating that. And what we decided to do was to use the results of an activity-based costing study project which was done in 1996 on the Ottawa district. Now, this project identified what are the direct assignment costs for lines and stations within the Ottawa district that could be specifically allocated to the assets, but they also identified a cost pool which cannot be allocated to specific assets, but really can be allocated on a pooled basis. So extrapolated the results from the Ottawa district study to the other Ontario Hydro Services Company districts, to obtain the totals for OHSC. And the net result was that the ABC study accounted for about 50 per cent of the OM&A costs. The remainder of the OM&A costs we allocated on the basis of net book value. We recognize that this approach is one of a number of approaches that could be taken to allocate. We feel that this is a good start. We've got some ways to go. In the model that is being pursued within Ontario Hydro Services Company, the asset management model and the formation of the service level agreements, we are fairly Presentation 695 (A. Poray - SERVCO) confident that this will allow us in the future to track the costs much more clearly and identify them specifically with the asset categories. The next slide, then, summarizes the allocation that was done using those various allocators to the connection revenue requirement and this then shows, the slide shows the result of that. The following slide shows similar results for the network revenue requirement. This is for 1999 and similar data is available in the submission document for the year 2000. And the following slide indicates just the total revenue requirement for connection and the total revenue requirement for network and the two add up to the total revenue requirement for transmission which is a good thing. Having then come to a stage where we've allocated the cost to the respective connection and network pools, we've determined the dollar determinant of the rate faction, if you like, or the rate ratio. So we now have to determine what is the determinant with respect to how customers use their transmission system, whether it should be demand or whether it should be energy. And this slide shows some of the considerations in that matter. In terms of the demands, the actual kilowatts is a driver for transmission utilization and investment, it's adopted by most other jurisdictions, it's supported by the considerations in the Market Design Committee. Presentation 696 (A. Poray - SERVCO) The use of energy may, in fact, potentially send the wrong signal to the market participants since the marketplace will be an energy-derived market. The transmission revenue requirement is not affected by the energy that's transported on the system; It's affected by the demand. This is generally not preferred by other jurisdictions, but it is a relatively simple means of administering a rate. So having identified the high-level rate determinants, we can now proceed to calculate the rates. For the purpose of this submission, we've adopted four principles: transparency, simplicity, rate stability and predictability. By transparency we mean that the rates are easy to understand and that customers could be able to readily calculate ahead of time what the rates will be, given the information that's provided in our submission. Also as envisaged in our regulatory regime, the rates will be predetermined; in other words, they will be determined ahead of time so that customers have that information prior to the market opening. Simplicity means that customers should be able to easily apply the rates to assess the costs that are going to be imposed upon them. Stability and predictability are important in that customers want to have some assurance that they can make decisions on the basis of rates we propose without having to worry about possible changes of variability of Presentation 697 (A. Poray - SERVCO) those rates. So in this context, we chose to use the non- coincident peak demand as the demand determinant for the rate calculations. This approach provides a readily traceable path and results in the simple and quick assessment of the customer demand. The result in rates are shown in this slide. So for 1999, rates for connection are $1.19 per kilowatt per month, and the rate for network would be $4.04 per kilowatt per month, and corresponding figures are given for the year 2000. Now, we thought to say it might be useful if we were to compare our rates with the rates that are available in neighboring jurisdictions and this slide shows that comparison. We have taken essentially our neighbours who are directly interconnected with us, but included some others that are within the market, the larger marketplace that Ontario Hydro generation has been known to deal with. I think one of the first things you should note is that the values for OHSC are 1999 values; whereas, as for the other entities, the best information we have is a combination of 1997 and 1998. I offer this comparison with some caveats that when you look at posted information in terms of what the rates are, it is not always very clear as to what the rate determinants are, what is the revenue requirement, what is the peak demand that was used. Presentation 698 (A. Poray - SERVCO) To the extent that these are filed certainly for the U.S. utilities using the FERC pro forma, there is some consistency in what is done there, but nevertheless I feel these have to be treated with a large grain of salt. It does -- they do, in fact, provide a useful comparison, a ballpark-type comparison. I think perhaps the interesting thing to note is that we are about the middle of the pack, but that generally our rates are higher, somewhat higher than the rates in the United States utilities, transmission utilities, but they are lower than the rates in the Canadian utilities. In general, Canadian utility rates are higher than U.S. utility rates. We don't have a good explanation without drilling down into the details of what are the revenue requirements and the peak demands that were used. But one of the useful comparisons that you may make is that typically U.S. utilities' transmission systems are much, much smaller than Canadian transmission systems on average. They span much smaller service territories. So associated with that you would expect to have higher costs in the transmission systems in Canada because of the size of the territory involved. Okay. That more or less brings me to the end of my presentation. I would like to just conclude by looking at how transmission service will be provided in the interim period up to the opening of the market and we Presentation 699 (A. Poray - SERVCO) indicated that in this slide. Essentially existing customers will see no differences. The CMO will manage the energy and reserve market and it will continue to perform the role of providing an integrated service. The bundled service will continue to be provided under a frozen rate guideline from the government and customers will not be seeing unbundled transmission service rates. Beneficiaries of any new connections between now and the open market will be asked to make capital contribution to leave the pool harmless. That concludes my presentation. MR. HARDY: Thank you very much. Why don't we begin then with Board Staff and Consultants questioning and then we will move to questions from participants. Again, for participants, this is an informal process. So when we do move to participant questions please come up and grab a mike and I will be pleased to take any questions. Why don't we start with Board Staff and Consultants then. QUESTIONING BY BOARD STAFF AND CONSULTANTS: MS. SIMMONS: Good morning. I am Susan Simmons from Reed Consulting Group, consultant to the Board Staff. Q. I am going to start with a couple basic questions. You referred to, I think it is page 4 of your [Questioning] 700 Board Staff/Consultants presentation, unbundled networking connection categories, this mothball test that you did, can you confirm, did you actually run power flow studies looking at taking load on and off at each particular connection point to determine what assets were connection and network? I wasn't clear the specific nature of your study. Can you expand upon what actually was performed? MR. PORAY: A. We didn't run actual power flow studies. What we did is we took the network, the network diagram and essentially went through it bit by bit looking at each customer connected to the 115, 230 and 500 and essentially removed that customer and see what would happen to the power flow. We didn't actually run, but just examined from a knowledge basis what would happen if that customer was removed. Q. Okay. In deciding to separate between network and connection you talk about that this approach is consistent with other jurisdictions. In other jurisdictions I'm aware of, I guess one of the things that I'm unclear, do they use pooling or specific costing for connection services? Are you aware of how that's done? A. I think for the recovery of embedded cost the general approach is to pool for new facilities after -- whatever the vesting date is. For instance, in National Grid the vesting date was the -- I think it was the 30th of March, 1990. Everyting prior to that was pooled, everything new following from that date would be [Questioning] 701 Board Staff/Consultants considered on a case-by-case basis. Q. For connection? A. For connection, yes. Q. For connection? A. Yes. Q. Are you aware of New Zealand and Australia, are they pooling their connection charges or are they charging them specific to individual customers? A. My understanding is that they are pooling, but I would have to go back and check on that. Q. Okay. I'm very curious as to what's being done and the discussions that went on in the MDC because when I look at your arguments between specific -- between needing to assign between network and connection and I look at your arguments between pooling and specific, I think you can almost say that some of your arguments for separating between network and connection also support specific costing for connection assets. I'd be very curious to find out some additional background, either whatever you can provide or whatever was provided to the MDC in making this determination. When you talk about separating between network and connection you refer to using net book value and in Appendix Q of the original filing, there is reference to this asset data base. A. Mm-hmm. Q. In your presentation, I can't remember if you referred to it, are you using net book value between [Questioning] 702 Board Staff/Consultants connection and network as it appears in this asset data base? A. The asset data base that we used is the 1997 asset data base as we indicated in appendix Q. The reason why we used the 1997 is that it was the most complete information that we had on the assets. Also, during 1998, OHSC was going through a process of changing its financial management systems and we felt that because of the detailed work of having to go into the assets and examine each asset, because it is so time consuming, that we would stick with the asset data base that we had which was the 1997. So the net book value ratios would have been calculated on the basis of the 1997 and then prorated for 1998. Q. What is the difference in net book value as appears in that asset data base with the net book value of the transmission assets that are included in your transmission revenue requirement? A. I don't have that figure with me. Q. Do you think they are close? I mean, are they a billion dollars off? I'm just trying to understand. A. No, they wouldn't be a billion dollars off, but there is continual transfer of assets going on or has been going on into the OHSC transfer out and transfer in. That's the other reason why we didn't use the 1998 data base because it wasn't settled yet. [Questioning] 703 Board Staff/Consultants Q. Are any of the assets that were transferred in and transferred out possibly connection-related assets that it would be important to take a closer look at it? I mean, what are the nature of the assets that are transferring in and transferring out? I'm trying to understand whether it would have an impact if we actually took the time and did the detailed asset-by-asset examination today? A. I think my understanding is that probably most of the assets, the major assets have been accounted for. There may be some that as a result of the demerger between transmission and generation that there is some migration of assets from one to the other. Q. Do you think it's mainly on the generation side? Is any of it happening on the distribution side? A. I'm not sure. I'd have to check on that. David, do you know? Q. Okay. MR. HARDY: There are a number of things that I've heard in terms of information coming forward. So I will note that you'll be bringing forward some information on whether it is the distribution or generation side in terms of costs indirectly assigned. MS. SIMMONS: Q. This asset data base, can you just describe what it is, what the contents and structure of it is and how it is maintained and populated? MR. PORAY: A. I'm sorry, can you repeat that. I was writing down. [Questioning] 704 Board Staff/Consultants Q. Sorry. The asset data base that you are referring to, can you describe what it is and what the structure of it is, how it is maintained and populated? A. Okay. The asset data base contains all of the information pertaining to the transmission assets. So it will contain the original capital cost, it will include the depreciation, it will include the OM&A costs, and also it includes the -- I think we include the customers that are connected to the particular facilities and the megawatts associated with that. Q. Okay. Is this something that someone is in charge of maintaining? And you reference that there are OM&A costs in there, is it something when some work is performed on a particular asset, does somebody go in and update that number, and when new assets are added, who is responsible for inputting those changes to assets or adding assets to the asset data base? A. We're trying to maintain the asset data base. We've just essentially last year established the asset data base for the transmission pricing. I guess as a result of the changes in our financial management systems there has been some reorganization in terms of who is going to have accountability for what. So we are trying to decide how best to manage that. Q. But it is your intention to continue to maintain it-- A. Yes. [Questioning] 705 Board Staff/Consultants Q. --and possibly refine it? A. Yes. Q. Okay. This asset data base, knowing that you are OHSC and you are responsible for transmission/distribution, does it also -- is it just a transmission asset data base or is it a complete wires asset data base? A. At this point in time it's transmission. Q. Okay. In Appendix Q, the appendix to the original filing, page 134 through 136, you make reference to the depreciation in there and you indicate that you attempted to use the asset data base to assign depreciation costs between network and connection, and then you indicate you weren't able do that entirely for the full amount of depreciation and that there was a difference between it. The difference is approximately 80-million and total depreciation is more than 200-million. That seems like a big discrepancy. So I'm wondering if you can just address how or why this occurred? Is it the condition of the asset data base and do you feel that the net book values are more accurate than the depreciation values in that asset data base so it is therefore reasonable to use net book value to assign depreciation? A. I think where the discrepancy occurred is potentially because there were some assets that may not have been -- when we did the original study that may not have been allocated. In other words, they weren't [Questioning] 706 Board Staff/Consultants transferred in. Whereas in the latest, the depreciation charges which are -- the total of the 209 pertains to what's in there today, so there may be some discrepancy from that perspective, but I think that's something that we could perhaps check. Q. So there's a discrepancy on the depreciation, but my concern is that you're using the same data base to assign the net book value as an allocator and so, do you feel that the net book value figures in there are more accurate than the depreciation figures? A. Well, we use the depreciation figures to allocate depreciation because they're asset specific. We use the net book values to allocate the other costs. Q. I'm going to try this one more time. Your depreciation was off by $80-million which to me, when you're talking about $200-million, is a significant discrepancy. If that was off by 80-million, how accurate is the use of the net book value figures from that data base? Why shouldn't I have the same sort of concerns about that same data that was in the data base being used as an allocator? Is there anything you can say to address my concerns? A. I can't answer that right now. Perhaps I can... MR. HARDY: I've noted that you've made a commitment to bring something forward to be able to provide us with some information on that. [Questioning] 707 Board Staff/Consultants MS. SIMMONS: Okay. We can continue to go on. Q. I'd like you to -- MR. HARDY: I'll wait until the panel is ready to go on perhaps. MS. SIMMONS: Thank you. MR. PORAY: Okay. MS. SIMMONS: Q. Okay. I want to talk a little bit more about your activity-based costing study and how you extrapolated the results of that study to the rest of the transmission assets -- or actually, to apply to the rest of the OM&A in there. Can you just explain to me, I was unclear that actually a study was used when I looked at Appendix Q and so I thought that you had assigned it somehow based on your own accounting practices and your projected spending levels for particular programs, sustaining development, et cetera, that you have here in this application. But when you gave your presentation just a short while ago, it appears that it's not based on your own ABC practices that you will be implementing but based on some other study that was extrapolated. Am I confused and can you help clarify whether you did it based on your proposed OM&A programs or based on some other study? MR. PORAY: A. Well, I think at the time when we were doing this, the best information we had in terms of how OM&A could be allocated to assets, to existing assets, was really the ABC study that was done on the Ottawa [Questioning] 708 Board Staff/Consultants district because that was the intent at that time, to actually -- to get an understanding in OHSC what the costs are associated with maintaining the assets. The study was done in detail in the Ottawa district and with guidance from the other districts in terms of how the costs should be prorated. We used that information to extrapolate it to include the other district to come up with the totals. Now we are effectively changing our processes and going towards this asset management model and service level agreements. To a certain extent, I believe that activity-based costing is still a part of that, but at the time when we were doing this, we didn't have this information and that information is not yet fully available. So we used what we had really at the time, the best information we had at the time. And as I said also, as I remarked, that this is a start, that, you know, we can go forward from here and as the information becomes clearer and more accurate and more readily available, we can then improve. Q. Okay. So it is your intention to actually incorporate in your network services and asset management structure to track work that's performed on the connection versus network assets just the same way you'll track distribution and transmission through that process? A. Yes. Q. Okay. But help me understand what occurred in this application. You used this ABC study to perform [Questioning] 709 Board Staff/Consultants some direct assignments and then you also used it to determine an allocation to assets. I'm -- A. The direct assignment was based on the information that came back from the study in terms of allocating specific work to lines and stations that was identified, so there were specific assets identified and costs tracked to those assets. But also in that study they found that there are other costs that were incurred in performing the work that couldn't be allocated specifically to the assets but to a pool of assets as a whole and this is the second component on that table on page 135. Q. Can you give me an example of those costs? A. Well, I think specifically the direct assignment would be to... Let me see. Q. Or an example of the other, the indirect assignment? A. Well, the indirect assignment would be more on a sort of -- like a network, network pool basis, to the network assets, some of the high-voltage assets as opposed to maybe some of the more radial-type assets, like transformers and radial lines. Q. I guess what I was looking for is, you mentioned you directly assign costs and you indirectly assign costs and those were based on net book value. What types of costs were indirectly assigned; are those overhead allocations? I mean -- A. No. These would be the costs incurred by the [Questioning] 710 Board Staff/Consultants district in operating and maintaining the transmission system in that district. It's just that it wasn't possible to allocate to specific assets, so they left it as a pool. Q. Are those the costs of, like, trucks and garages? I'm just trying to understand specifically why we can't assign certain costs to specific network versus connection so we know going forward that there's always going to be some sort of indirect allocation process -- or maybe there won't be. Maybe there will be some way that you come up with assigning it, but ... why do costs need to be indirectly assigned? Are they -- simply because they're used on both, like a truck that carries equipment and people to ... Is that the nature of the costs? A. I think there's some element of that, but I don't have that information with me. Q. Is that Ottawa study something that you can make available so we can have a better understanding over what sort of detail went into it? A. It is my understanding that the report was never written, that the results were used as they came out effectively, so we don't have a document per se that says 'Ottawa ABC Study'. Q. Okay. All right. MR. HARDY: Sorry, just to back-up then, on the -- I'm not sure whether you're proposing to, say, bring forward some more information on costs that are indirectly assigned to clarify that question or take that question [Questioning] 711 Board Staff/Consultants under advisement? MR. CURTIS: Yes. Actually I think that maybe if we could have an opportunity to go back and talk with some of the people that were involved with the ABC study, that we might be able to provide the additional information that's being sought here. MR. HARDY: Okay. MR. CURTIS: I think we could certainly provide, for example, details around what are the cost components that were directly assigned to assets versus those that weren't coming out of the Ottawa study, so I think we can provide more information on that. MR. HARDY: Thank you. MS. SIMMONS: Okay. I want to figure out where I'm going to go from here. I'm sorry, just a moment. Q. For your connection charges, you've proposed a pooling sort of approach. Were any studies done to look at how connection charges vary by connection point on your system to determine how reasonable the pool charges versus separate connection charges? MR. PORAY: A. We did some assessment in terms of looking at separating the costs and pooling the costs for a variety of customers, yes. Q. Can you give me some indications as to how those separate charges would vary relative to your proposed connection charge? A. I think there's a potential there for winners [Questioning] 712 Board Staff/Consultants and losers, that there are some entities that would be affected adversely by unbundling of the costs and there will be other entities that might benefit by the unbundling of the costs. So taking the existing pooled costs that today are essentially covered through a pool and unbundling those, may disadvantage some customers. Q. And -- A. And we felt that for the recovery of embedded costs, that this is not an appropriate way to go. Q. Okay. If a customer would pay a higher rate because they actually -- because of whatever reasons but that -- wouldn't that rate actually reflect their individual connection charges? I mean, it's higher because it really costs that customer more to connect to the grid and it presumably will cost them more to connect to the grid. Is that the case or am I...? A. No, indeed that is the case, but we have to remember that Ontario Hydro as an integrated utility made decisions in the past to connect customers to the system using a variety of reasons, whatever those reasons were at the time, and I think it's unfair to unbundle those historical reasons and potentially impose costs on customers because of virtue of those decisions in the past. So the simplest way to deal with that is really to grandfather the past decisions through the pooling and go forward into the new environment for any new [Questioning] 713 Board Staff/Consultants connections on a cost-specific basis. Q. So the existing connection -- the proposed connection charges, pool connection charge, for a customer where the pooled connection charge exceeds their actual connection cost, they cannot get out of paying that connection charge. They cannot bypass the connection charge by constructing their own facilities. Is that your proposed policy? A. I think for the recovery of embedded costs, there is a responsibility on the existing customers to pay for those costs and therefore they should not be able to bypass those costs, those existing costs. Q. But a new customer that comes tomorrow that can connect at a very low cost and does, it's in your opinion and the MDC's opinion, that that's okay because he's a new customer, because he came in, you know, next week? A. Well, essentially, we're entering a new era where customers will be connecting to the system using the connection codes and the requirements that are in the connection codes and the costs and they are essentially the beneficiary of that connection and therefore they should pay for that connection. Q. Okay. If a particular customer goes out of business or decides to move its plant across the province and then reconnects to the system, would they be eligible to then pay their new connection charges? MR. CURTIS: A. Yes, I believe they would, but [Questioning] 714 Board Staff/Consultants there would be provisions in terms of exiting from their previous connection at that point. I think the whole principle here that's been adopted through the MDC discussions is this demarcation between what has happened historically in terms of developing the system versus what will happen once the market opens up and we enter into an open access environment. It's my understanding that coming out of the MDC discussions that the recommendation is, that for existing facilities, that the existing customers still pay for those and when we add new facilities for new customers, that would be subject to the market rules and the open market, so there will be negotiations that would take place at that point for those. Q. Okay. A. So there is a distinction between the treatment of existing customers and existing assets versus the new customers and the new assets that way. Q. Are new customers responsible for paying the network charge? MR. PORAY: A. All customers who use the transmission system will pay network. Q. All customers pay network connections where we make distinctions between new versus existing; is that correct? A. Well, existing customers will pay for connection and new customers will pay for connection for their connection to the system, yes. [Questioning] 715 Board Staff/Consultants Q. And all customers will pay network? A. Yes. Q. Okay. It's important that new customers still bear a share of the embedded network costs, but connection, we're saying, is subject for separate treatment? A. (Nods). Q. And it's fair that we make distinctions between 'existing' and 'new' on connection, but it's unfair that we don't make distinctions between individual customers that are existing? MR. CURTIS: A. Can you go over that last point, the fair and not fair? Q. Maybe I said it wrong. It's unfair to make distinctions between existing connection charges, but it's okay to distinguish between existing and new customers? MR. PORAY: A. Well, I think the perspective is certainly -- Q. I'm just trying to clarify to make sure I follow the logic and I understand that it's the MDC's as well as your own policy that's being reflected here. A. I think the general perspective is that those customers, for whom the transmission system is built today, should bear the costs of that. For new customers who come on to the system, they will bear directly the cost of new connection because that's essentially part of doing business, new business, but they will also have to [Questioning] 716 Board Staff/Consultants pay the use of the transmission network and this seems to be the approach taken in other jurisdictions that have unbundled their transmission rates as well. Q. If a new customer connects to the system and they directly pay their connection charges, how would that connection require additional system investments to the network portion of system augmentation, reinforcement, whatever terminology you want to use, will those new customers will responsible for that? A. To the extent that you can identify a network upgrade to a specific beneficiary, then that beneficiary should pay. Once you upgrade a network, other network users tend to benefit from that. So it's -- it's a difficult exercise to try and allocate the costs to the specific user and that's generally why you put it into the network, but I think we recognize that if it's possible to identify that a beneficiary has caused that, that some of that cost may, in fact, be directly assignable to them, but maybe not all of the cost. Q. Okay. Now, these policies, the statement that you just made regarding treatment of new customers, are these going to be outlined anywhere so that -- are they going to be established in a transmission tariff? Are they going to be established in some sort of business practices for transmission on OHSC? How will a new customer know what you just told me? A. Well, the primary document will be the market rules so that a customer who wants to connect to the [Questioning] 717 Board Staff/Consultants system will go through the market rules and the follow market rules that will direct him on the path to connecting to the transmission system so they will go to the IMO and seek their input and then they will go to the transmission company to seek their input as well. Q. Okay. Returning back to a previous question. In determining whether a new connection requires additional system investment, how would you go about doing those studies and over what period would you look at in determining whether an individual customer caused the need for additional system upgrades, network upgrades? A. It is intended that the IMO will do those studies. They have the responsibility for directing the operation of the transmission system in the province and it's under their jurisdiction to look at the impact of new customers. Q. All right. So they will establish the study policies and procedures and possibly even charging costs for performing those studies? A. It's possible, yes. Q. Okay. I think at an earlier session, possibly the educational meetings, an issue arose regarding customers who own or partially own some of their connection facilities. And can you explain, is this a widespread problem, is this just a couple of customers who this applies to, and how you're going to deal with that in charging them connection charges? A. Most customers who today own their own [Questioning] 718 Board Staff/Consultants transformation facilities are not charged for the pooled rate. They, in fact, receive a transformation discount. The reason why we pooled out transformation from, as a separate connection pool, is for that reason so those customers do not have to be charged. Q. So those customers will not pay the pool connection charge going forward? A. Right. Q. Do you have any situations where customers are partial owners of those facilities or it's either you own it or they own it? A. It's more or less they own it and we own it. Q. I'm going to stay on the issue of connection charges. A decision was made not to assign connection charges to generators. And I'm curious, to the extent you know, are generators suppliers, whatever you want to refer to them as, assigned connection charges in some of these other jurisdictions that you refer to as your model or basis for your establishment of network versus connection. A. The main reason why we didn't assign connection charges to generators is essentially that, in the past, decisions were made to locate generators at various parts of the province as part of the vertically integrated utility for the benefit of customers in Ontario. And the connection facilities, as far as the customers are concerned, are really part and parcel of the network that delivers the electricity from those [Questioning] 719 Board Staff/Consultants generating stations to the customers. And we decided that the fairest way is really to put the connection into the network. In some cases, the facilities also tend to perform dual functions. They were, at one time, perhaps the incorporation facilities for a generating station, but today they also provide supply to loads in the area. Q. A new generator that connects, are they going to be responsible for their connection charges and is that true of the non-utility generators who are connected to the system? Are their connection costs and any sort of things rolled into the network charges? A. New generators connecting to the system will be responsible for their connection charges. Non-utility generators that have made contributions and paid for transmission facilities, those are not included in this rate. Q. It's just like the customers who own their transmission facilities then? That's the way it goes. Those non-utility generation connections that exist today, are all of them -- you don't have any separate transmission contracts for those interconnections to your system, there's no revenues that are coming from contracts that I should be concerned about? Those are all paid for by those non-utility generators? A. That is my understanding. Q. Your understanding? Is that the case? Is that the fact? [Questioning] 720 Board Staff/Consultants A. Yes, yes. Q. Okay. It was unclear in the application whether there would actually be a non-zero charge for wheels in and wheels out of your system. And I'm wondering whether you, at this point, can clarify what your proposed plans are or if it's dependent on some other action by the MDC, the policy for charging a non-zero rate for wheel in and wheel out? A. In terms of wheeling through and wheeling out, in the past these types of transactions are fairly unpredictable. They are short term and, consequently, to try and predict ahead of time what types of transactions will take place and what revenues will accrue from them is difficult, and therefore, we decided that it's not appropriate to put that into the rate base. In addition to that, the wheeling out and wheeling through service is really part of the market rules and therefore it will be offered by the IMO. In terms of the types of rates that can be charged, there are various points of view on this. Some say that you should charge anything from incremental costs to full imbedded costs of the transmission because they are users of the transmission system. Others says that you should just charge the incremental costs of congestion and losses. And the Market Design Committee decided that the latter, that they should just -- those transactions should only be charged the incremental cost of congestion and losses. [Questioning] 721 Board Staff/Consultants Q. So for both cases, wheel in and wheel out, to the extent there is no congestion -- A. No, no. For wheeling in, the load customers of Ontario pay for transmission so irrespective of where the generation is located there are no additional costs involved. Once the load customers in Ontario pay for the transmission, they can access generation in Ontario and outside Ontario. The issue that we are discussing here is wheeling through so Quebec wanting to wheel through to Michigan or Genco wanting to wheel out to New York or other jurisdictions. Q. And in those cases, they will just be paying the -- A. The incremental cost of congestion and losses. Q. And the incremental loss factors, will those be something that the IMO posts, to your knowledge? A. That hasn't been thought through or that hasn't been sorted out yet, but the IMO will have that responsibility of certainly advising the participants what they will be charged. I think, potentially, if you're going into incremental type pricing, it's not -- it's not ex ante, it's rather ex post; in other words, you tend to look at the impact the transaction has on the system as a whole in terms of whether you need to redispatch generation and what the incremental cost of that is and what the [Questioning] 722 Board Staff/Consultants incremental cost of losses might be, and therefore that will be billed through the settlement system to the transaction. Q. After the fact? A. After the fact, yes. Q. So if I'm -- so upward from Genco that's sold into New York will not know its actual transmission costs until after the fact? A. As I say, the details have not been sorted out yet. Q. Sure I understand that. A. Yes. MS. SIMMONS: Might be a good breaking point? MR. HARDY: If we could go for another 15 minutes or so. MS. SIMMONS: Q. There's a significant amount of projects associated with interconnection assets and I understand you've just told me that the MDC made a decision not to assign, not to charge, a portion of the embedded costs to wheel out or wheel in or wheel through transactions. At one point I did look at -- I read somewhere in the MDC report that the investments in these projects is a part of the market mitigation policies; however, the MDC recognized that these may benefit wheel- outs arguably more than they benefit, or equivalently benefit, the load customers in Ontario. And I'm wondering where or who made the decision that these interconnection projects were something that [Questioning] 723 Board Staff/Consultants were beneficial to the load customers? Is that going to be performed by anyone? Is that simply a decision that was made that's as a policy that can't be challenged? A. In terms of the benefit, there wasn't a rigorous study done in terms of identifying the benefits. The general perception of the Market Design Committee was that looking at market and market power mitigation, that if you expand the capability of the interconnections, you allow the incumbent generators in Ontario to access external markets, but you also allow the internal load customers to access external generation, so there is a benefit to the customers to perhaps access Quebec generation or cheap generation in New York if there is such thing and Michigan, so it works both ways. And generally, I think it's accepted and certainly for the interim - I have to be careful how I use the use the word interim because it has two meanings here - in the initial stages of the open market perhaps for the first 18 months to two or three years, it was agreed that any upgrades or additions to the network should really be rolled into the transmission rate base because it's really for the benefit of everybody. And that in the future, when locational marginal pricing comes into effect, that they will use the instrument or the instruments of locational marginal pricing will then determine the best process for, or the need for new investment, both on the interconnections and internally. [Questioning] 724 Board Staff/Consultants MR. CURTIS: A. And I know there have been a number of inquiries along this line and I think from our understanding is the assessment of these new interconnections was done on a qualitative basis. To the best of our knowledge, there is no quantitative assessment, a net present value, a net present worth study, that's been done in terms of determining where the benefits may actually go as far as these new interconnections. So it has all been done, these qualitative assessments assessments that Andy spoke about. Q. Do you recognize that the MDC indicated that interconnection or spanning interconnection capability is one market mitigation measure. The MDC specifically recommend the projects which you have proposed, the expansion of the Niagara capability through investments or, you know, the -- A. No. Q. The order of magnitude of the things that are being performed? A. The order of magnitude was specified. The 2000 megawatts was specified. Q. Okay. A. The decisions in terms of what would best meet that 2000 megawatts was done by ourselves. I think, if my recollection serves me correct, that Panel No. 2 spent some length in terms of discussing how those decisions were arrived at. [Questioning] 725 Board Staff/Consultants And I guess broadly speaking, the projects that we've talked about in terms of the interconnection with Hydro-Quebec and the Lake Erie project are the most economical ones. Q. One more question before we break. Can you tell me, given the order of magnitude of these projects, in designing your rates did you look at the impacts on the network charges as a result of making these investments? Do you understand some of them start in 1998 and some of them start in 1999 and some of them go on for 2000? Can you tell me how significant they had an impact on the network charge? MR. PORAY: A. We haven't looked specifically at the impact assessment of those projects, no. MR. CURTIS: A. But I think we could. I mean, I don't think that that would be too much of an effort in terms of calculating what -- you're talking about if we didn't do those interconnection projects what would the network charge be versus the rates that you see today which include those projects; is that correct? Q. Certainly if we see that the rate would change by 10 per cent and it would go from four to 390, then that tells that maybe this is the most efficient manner in which to collect them-- A. Sure. Q. --as opposed to a separate connection charge [Questioning] 726 Board Staff/Consultants which could impact how the market is utilized. So if you could perform those calculations I would like to see those. A. Okay. We can do that. MR. HARDY: I will note that. Why don't we break now. I have about twenty after ten. So about 10:35 or so we could reconvene. Thank you. ---Recessed at 10:20 a.m. ---On resuming at 10:40 a.m. MR. HARDY: Welcome back. At this point I would like to turn now to questions of participants and then we'll be returning back to Board Staff questions in the later part of the morning. Are there questions of participants? QUESTIONING BY PARTICIPANTS: MR. BACON: I guess I can start as usual. Bruce Bacon for OCAP. Just some questions specifically on page 198 of the application, if you want to turn to that. Q. Now, I understand the rates that you are proposing here are actually essentially transfer pricing rates and they're not going to be charged to customers and I understand that, but I guess in my questioning if we can assume they will be charged to customers in my questioning. I know through the interim period that's not going to happen, but after, as we get past 2000, [Questioning] 727 Participants potentially this rate structure could be used to charge customers for the transmission service I'm assuming? MR. PORAY: A. Yes. Q. Okay. On table 12-2, can you just explain exactly what those load determinants are? A. Okay. Basically the determinants that we used is the non-coincident peak of the customers for the connection pool and for the network pool. Q. Now, are those the monthly non-coincidental peaks added up and then is that the average-- A. Yes. Q. --monthly non-coincidental peak? A. Yes. Q. All right. Yes, I am assuming that customers would be billed on their non-coincidental peak on a monthly basis? A. They're actually billed on their actual demand on the past month. Q. On the past month? A. Yes. Q. So if they actually control that demand they would control their transmission costs? A. Potentially, yes. Q. All right. With regards to -- we talked yesterday about a true-up between the revenue requirement under revenue cap and the rates not -- the rates that are proposed or the rates that are approved do not actually collect the total revenue. I'm just wondering how that [Questioning] 728 Participants true-up process would happen? MR. CURTIS: A. I think, Bruce, we were I guess treating this as something that hasn't actually been developed yet. So I guess with that in mind, there would be in all likelihood a monthly review and certainly at the year-end there would be the true-up that would take place in terms of over- and under-collection as far as the total revenue requirement is concerned. There would be then, if the transmission business happened to collect more than what it was approved under the revenue cap, then there would be a credit, an adjustment to the next period rates that would occur, the next year's rates. Similarly, if there was a deficit, there would be a similar sort of adjustment over all rates then to recover that. Q. So in that light, the customer is actually bearing the risk of the volume forecast; is that correct? A. Well, the volume forecast has gone in to determine what the revenue requirement is for setting the revenue requirement for the transmission business. So in that sense it's the transmission business that's bearing the risk. What we're talking about here is how the transmission business actually goes about collecting based on that revenue cap. Q. Okay. Well, if you don't collect that revenue because you don't sell enough volume-- [Questioning] 729 Participants A. Right. Q. --then you would do some sort of true-up to the customer to make sure that you collect that revenue? A. In the following period. Q. In the following period. Which I would think that means the customer is bearing the risk of the volume because -- do you understand that? A. No, I can see I think what you're driving at. I guess what I was -- I think in terms of bringing forward a revenue requirement, however, there's an embedded expectation as far as what the load is actually going to be. That then gets reflected in term what the total revenue requirement is. So from at that perspective the transmission business is bearing the risk around the load forecast. Q. I don't know where to take it from here. I would suggest that if there is a true-up the customer is bearing some sort of risk on the volume, but we can leave it at that. Sort of along the same lines, I guess it sort of follows my argument along the same lines is that the PBR scheme that you are proposing is a revenue cap which I understand the company is bearing the risk of the costs up and down. Okay, I understand that. A. Yes. Q. I guess I am coming back to my argument that I think the customer would bear the risk of the volume. I [Questioning] 730 Participants don't want to take time to discuss that, but I'd suggest that. In order for the customer not to bear the risk of the volume, another way to do PBR would be a price cap. Would you agree with that? A. Price cap is another approach, yes. Q. Another approach. I think from my understanding of price cap PBR, the company would fully bear the risk of the cost as well as the risk of the volume because you are basically fixing a rate and the customer pays that rate and there is no true-up at the end? A. That's correct, yes. Q. So in that situation the company would bear the full cost -- bear the full risk of costs as well as volume, would you agree with that? A. Yes. Q. Okay. Thank you. Have you done any analysis on the winners and losers of your rate structure proposal here compared to what customers are paying now? MR. PORAY: A. Some very cursory. Not an in- depth analysis, no. Q. What do you mean by that as in cursory? A. Just to try and get a feel for what might be the impacts on a selected group of customers rather than doing a full-blown study. Q. Would that be available for us to review? [Questioning] 731 Participants A. I think we would have to look at that and see what our -- because there is confidential information involved in the particular customers that we analyzed, whether that -- how that information may be made available to you. Q. So is that something you would take under consideration and provide, if possible? MR. CURTIS: A. I think we can take it under consideration, Bruce, but I think it's highly unlikely that we actually would be able to provide it to you because, as Andy was saying, it's dealing with then specific customers and what the financial implications to those customers would be. So I think we can take a look at it, but -- MR. HARDY: Bruce, I have noted here that there is some information that may or may not be coming forward. Brian, did you...? MR. HEWSON: I was just going to ask Dave if you can provide something like you have provided in previous Hydro hearings where you gave sort of percentage impacts on groups of customers related to this? You have sort of shown the top five customers, how much they get impacted, and then grouped it around half a per cent impact, 1 per cent impact, 5 per cent impact and 10 per cent impact. Something like that would be useful. And I think the Board would definitely need to see something that would give it an indication of how this [Questioning] 732 Participants new rate structure is going to impact on customers. MR. CURTIS: Yes. I think that's probably the format that we would present it in. MR. HARDY: I have made a note of that. MR. BACON: That would be acceptable, sure. Q. This is my last question, Dave. You mentioned if it comes back to what you were talking about first thing this morning, you mentioned that report that you put forward to your consultants or to your -- are you bringing that forward? MR. CURTIS: A. Yes. We will make copies of that available. Q. I just wanted to confirm that. MR. BACON: Thank you very much. MR. HARDY: Thanks, Bruce. Go ahead, Richard. MR. STEPHENSON: Richard Stephenson for the PWU. Q. I want to come back to the actual rates that are proposed, the connection and network rates which appear at 198 of the record -- or of the application, rather. Again, I realize that these are not being charged in any direct sense to any specific customer in this proposal, but nevertheless these rates are, I guess, embedded in the actual bills that customers will receive in some bundled form in '99 and 2000; is that fair? MR. PORAY: A. I think the word embedded, yes. The actual rate is not calculated. The costs are there. [Questioning] 733 Participants Q. Right. I guess what I am wondering is -- and that's true for all customers, right down to residential customers of any use obviously because they have a network charge that is passed through the MEU; is that fair? A. There isn't a specific network charge that is passed to the MEU today. Q. It's embedded in there is a proxy -- A. The end-use customers that today pay, in their electricity bills pay for the generation, transmission and distribution. Q. They still -- and they will continue to do that on a bundled rate basis. What I was wondering is this, that obviously you've expressed these rates in kilowatthours, dollars per kilowatthour per month. A. Dollar per kilowatt per month. Q. Per kilowatt, sorry, per month. Certainly residential customers pay their bills in kilowatthours and I guess there are some variations on that depending upon where you are and how it is calculated, but can you provide us anything which give us a couple of sample customers showing what their consumption in a month would be and how this number would fall out of their monthly bill? A. First of all, this is the charge for transmission of the wholesale level. So this only includes the transmission component. Q. I understand that exactly. I understand that [Questioning] 734 Participants this is embedded and they don't see it in any real way, but it would be useful to understand that for whatever typical consumer residential level or maybe even a selection of typical consumers based on some typical bills that they face, you know, "X" hundred dollars a month based upon that consumption, they would be -- embedded in that bill would be "X" dollars or "X" cents or whatever the amount is in relation to transmission. Is it possible to generate that kind of information? A. Do you think it would -- are you looking for something over and beyond what was provided in appendix H of the December 23rd supplementary information? There's a breakdown there of a notional customer and it's an all-in bill. Q. I see that and I guess there is -- the thing I think I perhaps don't understand is, there is variations in the monthly network charges based upon individual customers' monthly peak demand; do I have that right? A. The rate doesn't change, the charge will-- Q. The charge, yes. A. --depending on what megawatts -- the actual kilowatts they're actually taking. Q. Right. And those are obviously -- you're talking about transmission customers-- A. Yes. Q. --and not end user customers where you're talking about customers of another -- of a distribution [Questioning] 735 Participants utility. I take it, for example, individual Ontario Hydro retail distribution customers, can you tell us how -- I mean what the assumptions are that you've got in here in terms of what their usage is and whether or not individual usage in any way affects the transmission component of what they're paying on a monthly basis? MR. CURTIS: A. Which customers are you talking about; are you talking about -- Q. Let's start with your SERVCO retail customers, okay, just as an example. An individual residential SERVCO customer, will their actual consumption affect in any meaningful way the amount they pay for transmission on a monthly basis, fluctuations up and down? MR. PORAY: A. I'm not sure I understand the question fully. So I mean, their bill will depend essentially on what -- how many kilowatts they consume over the month. Q. Yes. I understand what a bill looks like. The question is -- embedded in that is a transmission component and the question is: To what extent does their individual usage on a month-to-month basis vary in terms of the transmission component on a month-to-month basis? I take it that there's not necessarily any correlation between the two. Individual on SERVCO retail customers could double their consumption in a given -- [Questioning] 736 Participants from month to month and it wouldn't affect the transmission component that they've been charged. MR. HARDY: Richard, just a clarification of the question, is a premise of the question that there are different rates that would be charged to different customers based on the characteristics of their usage; is that ...? MR. STEPHENSON: No, not at all, no, sorry. Q. I thought it was a simple question, is, I'm a distribution customer. I live in the Ontario Hydro -- SERVCO district. In February I'm in Florida and I have very little usage. In March, I double, I come back and I double my usage. My bill obviously will double assuming it's, more or less, based upon my energy usage. The question is: In terms of -- embedded in my bill is a transmission component presently, but I'm not -- that is based upon the Ontario Hydro distribution company's peak monthly demand I take it. That's how you're going to determine the transmission component that Ontario Hydro retail customers are going to be based paid -- or charged rather. MR. CURTIS: A. I think one of the problems that we're having with your question, Richard, is around the time period. Like, this question that you're posing, are you talking about this being within the period leading up to open access-- Q. Yes. [Questioning] 737 Participants A. --when rates are frozen? Q. Yes. A. Then I think the answer to that is, that you're still dealing with a bundled rate and those bundled rates are -- for the distribution customers are largely determined by their energy consumption, so that's still how your bill would be determined. So in terms of your variation as far as monthly peak is concerned, there wouldn't -- in terms of how distribution rates are calculated, there wouldn't be a strong factor as far as your actual peak. It gets reflected in terms of your variation in the use of energy. Q. I guess I want to know -- just using your chart at H, supplemental filing H, I take it there's some assumptions that go into this chart about, for example, what the peak demand is for these various customers are and what their energy consumption is; is that right? I mean, surely these are not -- these are subject to variation. This is a sample. A. No, it's not a sample. It's a notional average customer in the province of Ontario and the notional rate is that they pay based on 7.2 cents per kilowatthour for -- Q. I guess what I want to know is, what are the notions behind -- what are the characteristics of that notional average customer? Can you provide that for us? MR. PORAY: A. I don't think we actually -- that this was provided based on any notional characteristics of [Questioning] 738 Participants a customer. I think this is just the average rate across the province broken down into components. So there will be some customers that pay more than 7.2 cents per kilowatthours and there will be other customers who pay less than 7.2 cents per kilowatthours, but the purpose of this was really just to break down the components of the average rate. Q. I'm going to have to take another look at it. That's -- MR. HARDY: We can come back later ... MR. PORAY: And I think -- well, just in relation to that, you could see that perhaps the transmission component of that is 1 cent of the 7.2 cents. MR. HARDY: Could I suggest that we'll come back to this area? Okay. Did you have another question that's in another subject area? MR. STEPHENSON: I'll come back to it. That's fine. MR. HARDY: Okay. At this point, I've been informed that one of our Board Staff has a time constraint, so I'll beg your forgiveness, but I'd like to move to Brian Hewson to ask a series of questions and then I'll come back to participants. QUESTIONING BY BOARD STAFF AND CONSULTANTS: MR. HEWSON (Board Staff): I'll be very brief. I just want to -- I may not be back in time to catch you [Questioning] 739 Board Staff/Consultants this afternoon. If you guys are lucky, you may be done before I get back. I just had a couple of questions on a few random topics, so I'll jump around a bit. Q. In terms of your new connection charge where you're talking about charging customers for a new connection specifically identifying those costs, how are you going to deal with the replacement and refurbishment of existing equipment? If you've got an existing customer paying a charge and the equipment starts to wear down or maybe something unfortunate happens or unanticipated happens, how do you anticipate dealing with that situation? MR. PORAY: A. The ongoing costs for the existing equipment are part of the rate base. They're included in the rate base. Q. Even if you have to go in and replace, you know, the entire transformation station or something because of some accident, they'd continue with the existing charge? A. I think it still gets rolled in. MR. CURTIS: A. It would still get rolled in. Q. Sorry, just -- that answered a couple of my follow-up questions. Now, in the interim you're planning to seek a contribution from any new customer, is it your anticipation that contribution would represent 100 per cent of the cost for connecting a new customer or ...? I [Questioning] 740 Board Staff/Consultants guess it would include expanding for an existing customer their connection or their capacity. MR. PORAY: A. Any additions to the capability would be done in such a way as to keep the existing pool harmless. So if the costs can be accommodated within the pool without the pool price going up, then that's fine; if it can't, then there will be a capital contribution or an incremental contribution above that amount that would keep the pool harmless. Q. So you'd be doing some sort of a net present value analysis over a period of time? A. I would imagine we would do some sort of analysis to try and determine, yes, how it would impact on the pool price. Q. Okay. Do you do that currently? Is that a type of study that you could provide us with so we could understand what you currently do in terms of that kind of analysis? MR. CURTIS: A. I guess the problem is that again we're talking about specific customers in terms of doing these calculations. If you're talking about maybe the general methodology and that sort of process -- Q. That's what we'd be looking for - what are the parameters that you include, what's the general methodology? We've got similar tests in the gas industry. We don't want to look at your specific customers' numbers, but that would be helpful. [Questioning] 741 Board Staff/Consultants A. Yes, I think we can bring that forward, Brian. Q. And, Andy, just following up on the idea of doing that in the transition, did you consider that as a possible way of going forward with connections; I mean, doing an analysis and saying, this connection may have some benefit for some other reason to the system or may provide additional revenues that make it appropriate to allow it to be rolled in in the future? MR. PORAY: A. Well, I guess the question that we have to answer is, how long do you want to maintain the existing pools? Is it maintained ad infinitum in which case you'll keep adding to it or do you take the existing facilities and allow the pools to run down and then start up new pools for new facilities? The MDC's general perspective was that ultimately the existing pools should be allowed to run down. Q. Now, you said earlier, just bringing up the MDC, that the market rules -- I know there will be something that will establish the reliability and security conditions for a connection, but I didn't anticipate that the market rules would in any way establish how you would recover the cost or what the appropriate costing of a connection charge for a new customer is; is that correct? A. That's correct. What would happen -- the process that would happen for a new customer is that they would go to the IMO to indicate to them that they want to connect to the system. The IMO would do -- through the [Questioning] 742 Board Staff/Consultants market rules and through the grid code that's in the market rules, the IMO would then do an assessment, an impact assessment, to determine what's required. And then once they've satisfied themselves that it's possible for that customer to connect, that customer would then approach the transmission company and enter into a connection agreement with the transmission company to connect to the system in accordance with the connection code which is a requirement of the transmitter's licence. And as part of that agreement, there will be the financial aspects of how the costs would be recovered. Q. That's what I was trying to get to, that there would actually be an agreement between yourselves and the customer that would set out any of those details. A. Yes. Q. I think you may have touched on this with Susan, and I apologize if I'm covering it, I'm a little bit still confused in terms of your cost allocation. I can understand how you've identified, you know, specific transformation stations as part of connection and specific parts of the wire system. What I was wondering about is more the general plant. I mean, there's usually a fairly large amount of operating personnel, executive, head office, there's a lot of other costs there that aren't usually easily identifiable as one activity or another activity. And could you tell me how that's been costed and if you've done a study that you could provide that would show us how [Questioning] 743 Board Staff/Consultants those costs have been allocated? MR. PORAY: A. Well, I think we've treated them as part of the OM&A cost and allocated it and, I think that's -- yes, and allocated it both to network and connection using the net book value ratio. Q. So where you have general plant like warehouses or, I don't know, trucks and equipment like that, you've been allocating that out? A. To both connection and network. Q. On the basis of? A. Of the ratio of the net book value of the assets. Q. Now, with regard to the export service, I might have been confused with what the MDC ended up recommending -- or is thinking about recommending. And I had understood that their concern was that you shouldn't be pancaking a transmission charge on another jurisdiction if they are not pancaking back into when they are doing transactions into Ontario. But there may actually be a charge -- I mean, you could actually charge the full transmission charge to the entity receiving the power at the border point if the situation was that that entity operated in a marketplace where they did not have such progressive views on transmission; is that correct? A. That was debated at the MDC, but the final decision was to go with incremental marginal costing or pricing for -- it was recognized that there are jurisdictions today that use exactly what you've said, up [Questioning] 744 Board Staff/Consultants to rates, which allow them to recover anywhere between a marginal rate and the full embedded cost. But they felt that there is sufficient -- that there are some entities that are not satisfied with the way things are done under the current FERC jurisdiction and therefore the MDC went in the direction of trying to leapfrog and establish a system where you would, in fact, avoid pancaking and price the use of out and through transactions on a marginal basis. Q. Okay. Thank you for that. So would you say that this is -- I know one of the issues I think you've raised in your filing is trying to make your rate design consistent with other -- or acceptable to other jurisdictions and I'm presuming that has -- in some respect that deals with FERC compatibility so that generators in Ontario may be able to get their marketing licenses. Is it your view, broadly then, that you've achieved that with the proposals that you've come forward with? A. I think in taking the rate and the market rules together and the developments that are taking place in Ontario, I think that's -- that's -- yes, it's consistent. Q. Okay. Now, given that the market rules won't be implemented until sometime in the Year 2000, during the transition period, for want of a better phrase, would you consider your proposal for allowing export and wheel- [Questioning] 745 Board Staff/Consultants throughs to meet, again, the FERC requirements? A. My understanding is that -- that there will be no wheeling out or through during the interim period because that's synonymous with open access. Q. Well, am I not correct in -- I mean, the generation company will be wheeling in power, correct? A. Well, they can see still wheel, they can still sell at the border. They don't necessarily have to wheel it through. They can do what they do today which is sell at the border. Q. The last question I had was on pages 194 and 195, you talk about the process for establishing the rates each, I guess it's each year, and I just had a clarifying question about this process that you've got down. You talk about the OEB approving of the peak demand forecast provided by the LDCs. Is it your view that the Board should sort of be absolving you from that risk by approving those plans and therefore saying that those are the set amounts for each customer? Was that the intent of what you're saying or are you saying that -- MR. CURTIS: A. Yes. Q. So you'd be coming forward with a forecast? MR. PORAY: A. With a forecast, yes. And that that forecast would be embedded in the approval of the rates. MR. HEWSON: Thank you. That's it. MR. HARDY: Okay. Thank you. Let's now return [Questioning] 746 Participants to our participants. Are there participant questions? Mr. Snelson, go ahead. QUESTIONING BY THE PARTICIPANTS: MR. SNELSON: Okay. Ken Snelson representing AMPCO. Q. I wanted to come back first to the issue of connection costs and particularly line connection costs. And you have, to some degree, discussed it that there are in addition to transformer connection costs, that there are lines that form part of the connections from a customer or group of customers to the main interconnected transmission network. Can you confirm that the MDC in its third quarter report recommended that new line connections should be paid for by the connecting party? MR. PORAY: A. The recommendation in the fourth -- in the-- Q. Third quarter. A. --third quarter report was to separate those, yes. Q. Yes. And while we don't yet know what will be in the final MDC report, can you confirm that at the Technical panel level, there was extensive discussion about creating a separate pool of costs for connection lines? A. Yes. Q. And as I understand the concern, it was that [Questioning] 747 Participants if the connection costs were rolled into the network charge, it could be unfair to a new customer. A new customer would pay for his own connection lines, and he would also pay a share of everybody else's connection lines through the pooled network rate. Now, can you confirm that the proposed solution to this problem was to create a separate pool of connection line costs, this would initially be paid by all customers because their connection lines are rolled into the pooled cost; however, new customers who have to pay their own connection costs would not have to pay the pooled connection costs? A. Yes, I confirm those discussions took place. Q. Now, OHSC's proposal does not separate the connection lines and network lines but after the market opens, then we are presuming that new customers will pay for their own connection. And can you confirm that this does produce the potential for, or the effect, of double charging for connection costs that was of concern to the T and D Technical panel? A. If we were go to go forward with this, yes, there would be that concern. Q. And why has OHSC brought forward a proposal that will create double charging for line connections? A. I think in fairness, as things were developing in parallel, we didn't develop an understanding of what impact there will be on customers by removing the line connection, by keeping the line connections within [Questioning] 748 Participants the pool and removing the line connections from the pool. We haven't done the assessment of the impacts. Q. Okay. A. Although we recognize there's a potential, we don't know to what degree. Q. Moving on to something that was just mentioned this morning, and I think it was David mentioned that a customer who closed his facility would somehow or another be held responsible for the continuing costs of transmission to that closed facility and that was something new to me and perhaps you could expand further on it? What is the charge to a customer who closes his facility? MR. CURTIS: A. I don't know if we know what the exact structure, Ken, is going to be, but I think it's following the broad principle that the MDC talked about in terms of existing customers paying for historically installed assets, at least as a broad principle, should not be able to bypass those historical responsibilities. I don't know that an actual mechanism has been sorted out in terms of, you know, all of the aspects of it but my comment was really in terms of the balling-up as the illustration was being developed this morning. Q. Okay. In the current rate system, if a customer closes his facilities, is he liable for any continuing costs for transmission or generation? A. You mean under the current structure, current situation? [Questioning] 749 Participants Q. Yes. A. I'm not sure. I think we'd have to -- have to have that looked at. Q. Well, my suspicion is that apart from any agreements he might have signed at the time he was connected, to pay for specific facilities or to guarantee a revenue requirement, but apart from those specific agreements that, if he's just being supplied under standard rate, then if he terminates his supply then he terminates his bill? A. You may very well be right, but I think probably we should check into that and find out. MR. HARDY: I've got a note then that they're going to be bringing forth some information. MR. SNELSON: Q. I wanted to move on to some questions of one of my favourite subjects which is diversity and I want to ask you whether you agree that in the current rate structure, almost all of the transmission cost is recovered through peak charges and the allocation of peak charges is at least partially recognized as the diversity between customers' billing loads? MR. PORAY: A. Yes, that's the way it's done today. Q. And as I understand it, the diversity within a municipal utility between its component loads and the load at the delivery point is fully recognized? A. Yes. Q. The diversity within the direct customer [Questioning] 750 Participants class is also recognized? A. In today's rates, yes. Q. And the diversity between the direct customers and the Ontario Hydro retail load in coming up with a load of the power district is recognized? A. It is today. Q. And in the new scheme, if I have it right the diversity within the municipal utility will continue to be recognized? A. Mm-hmm, yes. Q. The diversity within the direct customer class will not? A. In that sense, yes. Q. Have you done any studies to show what the impact would be of recognizing or not recognizing the diversity within the direct customer class? A. We've started doing studies, we haven't completed those studies. We are gathering data and trying to fill in blanks but our intent it is to look at the impact of moving from where we are today to a uniform transmission, what a uniform transmission price across the province would mean to customers. Q. Wouldn't it be normal to do the studies before making the proposal? A. I guess under normal circumstances that would be the case, but in this -- in this particular submission because there were, I guess, things outside our control, we did what we thought was the best and the simplest [Questioning] 751 Participants approach recognizing that there are many ways that you can derive rates to take into accountability, diversity. But as a starting point we felt that the simplest way to do this is to just treat all transmission customers on an non-coincident basis. Q. I don't necessarily agree with the answer, but then we have the answer. I have in front of me Exhibit 2.1.1 from the OEB hearing HR 23, which was to establish 1996 rates for customers. I'm looking at schedule B-1. You don't need to turn it up. You probably don't have it. MR. HARDY: Sorry. I just should ask the panel what they need. Do you need a copy of the information? MR. SNELSON: If they could perhaps just hear the question and then they would know whether or not they needed the document. MR. HARDY: Let's hear the question then. MR. SNELSON: Okay. Q. And the direct customers in this document are shown having a winter coincidence factor of 87.2 per cent to the power district load and the corresponding summer figure is 84.56 per cent. I don't think we need to talk about the specifics of the numbers to the decimal places, but given the substantial degree of diversity, would you agree that it will make a significant difference to the direct customers as to whether their diversity continues to be recognized? MR. PORAY: A. I appreciate your concern, Ken, [Questioning] 752 Participants but without actually doing the analytical assessment I can't quantify that and say it will have a significant impact. Q. The coincidence factor of 87 per cent effectively implies that there is diversity of 13 per cent. I believe that would be the inverse of it. A. Well, as I say, I would feel more comfortable if I had some analytical results, but I don't at this point in time. Q. Okay. Now, we are working on non-coincident peak load and I wanted to know a little more detail about how you're going to assess the non-coincident peak load for billing purposes. The first question is: How do you measure the non-coincident peak demand for a municipal utility or large user that has more than one supply point? A. I guess we do it -- we look at the maximum reading on the meters to the MEUs across the multiple feeders. Q. Okay. So if you have several feeders to an MEU, then you send them all on an hourly basis and then you look for the monthly peak of that sum load? A. Yes. Q. Okay. I asked that question in December at the information session and was told that you didn't know, but I'm pleased you know now. The question that I also asked in December was how you would treat the multiple delivery points to the [Questioning] 753 Participants Ontario Hydro Services Company distribution system and I was told in December that however you did it to the municipal utilities you would do it the same to Ontario Hydro distribution. A. Yes. Q. And if you charge Ontario Hydro System Distribution Company on the basis of the peak demand of the sum of all its delivery points throughout the province, won't this give them a significant benefit that is not available to other load distribution companies because they will capture the diversity between the winter peaking loads in the north and the summer peaking loads in the south and any other diversities that might occur? A. It's possible. Q. Doesn't -- if you have a municipal utility that has several feeder points and it merges with another municipal utility that has - well, it doesn't actually matter whether they have one or more feeder points - if a municipal utility merges with another municipal utility, would you then start to calculate the peak load of this now combined utility or would you continue to carry on with the peak loads of the original constituent municipal utilities? A. I think we would do it on the basis of the metering volumes. Q. What you've told me is that for a municipal utility that currently has more than one delivery point, you will sum them before finding the peak? [Questioning] 754 Participants A. Right. Q. So I presume that if you were to follow the same procedure with a merger of two utilities, then you would take the now merged utility and sum all its delivery points and find the peak of the now larger municipal utility? A. I think that's -- yes. Q. Doesn't this create an incentive for utilities to merge, particularly if they have different load patterns that have peaks at different times? A. It's possible. Q. Isn't it a general property of non-coincident peak measuring schemes that to get the lowest rate you actually want to be grouped together with other customers who have as widely different a pattern of load from your own as possible to capture the maximum effect of diversity? A. Yes. I guess it could be, yes. Q. I wanted to come to the effect of diversity on the connections and on the network. And I think you'll agree with me that diversity factors in coincidence with system peak are not relevant considerations to a connection that serves only one customer? A. Right. Q. And as you group customers together, and perhaps you have a connection that serves a group of customers, then the load that is of concern to the design [Questioning] 755 Participants of the system is the after-diversity load; that is, the combined load of the two customers together, rather than the sum of the loads whenever they might occur? A. Right. Q. As you go to bigger and bigger groups of customers, the effects of diversity become more significant? A. That is true. Q. Can you agree with me that as you get to a group of customers that is a significant proportion of the system, the resulting load pattern looks more like the system load shape than the load pattern of any individual customer or the sum of customers' loads without taking into account coincidence? A. I think if it was a homogeneous transmission system I would agree for the system as a whole, but the transmission system is not homogeneous and there are essentially pockets within the transmission system which have different patterns. Q. But those different patterns are not determined by adding up loads at different times; they are determined by adding up the loads that occur at the same time? A. I would say within geographic groups, yes. Q. As you know, I'm -- I believe there is some benefit in the separate pooling of line connection costs, and I wondered if you had considered a scheme where a pool of line connection costs would be charged on a [Questioning] 756 Participants non-coincident or on a contract basis and the pool of network costs, because the network is dealing with larger groups of customers, was to be charged on a coincident peak methodology? A. We haven't considered that, but we agree that there are various ways of doing it, yes. Q. I have some more questions about individual things, but if other people want to go in here, this would be a suitable point to break. MR. HARDY: That's fine. I'll see if there are other -- are there other participants that wish to ask questions? Welcome. Could you introduce yourself for the purpose of the record, please. MR. ANGEMEER: Mike Angemeer from Hydro Mississauga. Q. Just a couple of clarifications on the wheeling out and wheeling through. Will you say that if there aren't reciprocal arrangements with outlying areas from Ontario that what you have talked about before puts the wheeling-in customers at a disadvantage because they will be paying pancake transmission rates both outside the province and within the province? MR. PORAY: A. There is a potential for that, yes. Q. So is there any intent to try and encourage other jurisdictions to follow our lead or how is that going to be over time made more fair? [Questioning] 757 Participants A. As there is more and more dissatisfaction with the administrative type approach to pricing of transmission for out and through transactions, I think other jurisdictions will move towards alternative methodologies, and FERC is certainly very interested in hearing other methodologies and PJM has adopted locational marginal pricing and I understand that New York is going in that direction as well. Q. Can you confirm that the part of the Market Design Committee recommendations were that after market opening the new investments in interconnection facilities would be partially funded by the beneficiaries or the generation companies that were going to be exporting? A. The Market Committee did consider that and said to the extent possible that you can identify beneficiaries for the interconnection, then yes that would be done. Q. I will move to a different line of questioning. In your presentation on page 15 you talk about existing customers not seeing any difference. So from that and from some of the discussion that followed, I'm assuming that the combination of the network and the connection and any low voltage connection charges that may be put in place we should see no difference in our portion of the charges that are coming to us in the transition period? A. My understanding, yes. Q. Will those low voltge connection charges for [Questioning] 758 Participants low-voltage feeders that are currently owned by Ontario Hydro be charged by the distribution company? A. It's my understanding, at least the direction that the Market Design Committee was going in that, yes, those would be part of the distribution rates. Q. I guess my last question is on the new connections and maybe referring to a specific example on page 38 of the supplemental filing 1 concerning a transformer station in my area, in Mississauga. I just want to clarify -- MR. HARDY: Michael, I need to follow-up. Which supplemental filing? What date was that? MR. ANGEMEER: Filed January 4th, '99. MR. HARDY: Page 38. So tab I? MR. ANGEMEER: Yes. MR. HARDY: Okay, thank you. Sorry. Go head. MR. ANGEMEER: Q. I just wanted to clarify some of the discussion that occurred before on the charging of a new connection and how that's going to occur through the transition period. This is an example of a project that's going to take place I guess during the transition and also after 2000, and I just want to make sure my understanding of this is correct that it looks like the funding would occur from Ontario Hydro transmission company for a portion and then that the beneficiaries, Brampton and Mississauga, would be responsible for the remainder after the 2000 period. Is that the way you see that? [Questioning] 759 Participants MR. PORAY: A. No, certainly up to 2000 that's the case. After 2000, the general direction is to make new connection contestable and the beneficiary pay for the full cost. Q. So up until that point you will be funding the connections that are in progress? MR. CURTIS: A. I think for this particular one that you are talking about, I think this is one of the projects that's considered part of the interim period. I believe, and we should check that, that this falls under the considerations for existing connections. So it would be funded to completion by OHSC. MR. ANGEMEER: Thanks very much. MR. HARDY: I wonder at this point if I can return to our Board Staff and Consultants. I'll certainly come back to participants. If I can get an idea of how long you ... not long, okay. We may get out a bit early today, so go ahead. QUESTIONING BY BOARD STAFF AND CONSULTANTS: MS. SIMMONS (Reed): Okay. Just one second, I want to turn back to the transmission section of this application. I apologize if you want to repeat yourself, but I do want to clarify some of the information that was presented here based on some follow-up questions that I've heard this morning. MR. HARDY: What page are you on? [Questioning] 760 Board Staff/Consultants MS. SIMMONS: I'm on page 198. MR. HARDY: Thank you. MS. SIMMONS: Q. And I want to understand how these determinants were derived because I think I had a different impression as to how they've been derived and I want to confirm how you're going to be deriving billing determinants going forward. These load determinants for connection and network that appear here I assumed were the non-coincident peaks at all of your connection points; however, after hearing some discussion, it sounds as if it's not necessarily based on any metering point. It's actually based on customers who may have multiple connection points or multiple metering points and I'm wondering if you can just explain to me what these determinants represent and how that's consistent with what you've indicated in terms of how you will bill customers who have multiple metering points. MR. PORAY: A. Well, I think we've taken that into consideration in deriving these determinants for the connection. That's why, in fact, you see a difference in the megawatts, to account for the fact that some customers are not in the connection pool because they own their own transformation, but also, we've taken into account the various metering points in deriving the megawatt demand. Q. Okay. And in follow-up to the other questions, was it the MDC who indicated that billing both connection and network on the basis of non-coincident peak [Questioning] 761 Board Staff/Consultants by customer was the appropriate, you know, rate design methodology to use or was that Ontario Hydro Services Company's decision? A. The Market Design Committee did not specify that it had to be non-coincident peak. It was just based on demand. And we decided that the simplest way of doing it moving forward in unbundling transmission was to use non-coincident peak demand. Q. Is there a technical reason as to why you couldn't bill connection on non-coincident peak, however you want to aggregate that, and network on the basis of the customer's contribution to the system coincident peak so given peak hour of January, you'd take into account each individual customer's load at that time and bill network on that basis? A. It's possible to do it a number of ways, Susan. One of the disadvantages that we thought of using at coincident peak hour is the free-ridership issue where if people know what hour the peak is going to occur, they may want to not -- you know, not to take power at that time but to take power at another time; in other words, if you have an entity that has the ability to shift their operations from different parts of the day, they may, in fact, miss-out the system peak and avoid the transmission charge based on that. So we tried -- we recognized there are a number of issues associated with moving from where Ontario Hydro is today and charging a bundled rate which allows for [Questioning] 762 Board Staff/Consultants diversity, as Ken has pointed out, between the various customer groups to an environment where you have one set of transmission customers so that we don't differentiate effectively between the large direct industrial or the MEUs that are connected to the system and trying to keep in perspective that we want a uniform transmission rate across the province. So given those things, we thought the simplest way to do this is just to use the non-coincident peak demand. Q. So based on what you just said, if you're concerned about customers modifying their behavior, in effect, avoiding transmission costs which are embedded embedded costs which you think rationally should be collected from existing customers, why don't you just simply establish customer contracts for transmission and avoid the whole issue of measuring demand and billing demand which non-coincident peak can be shifted month to month and we could have true-up problems? Was that considered and can you give me any reason as to why that's an impractical solution? A. Well, I think for connection, that may not be a problem. For network, I think it potentially is a problem because you're trying to establish a uniform rate for all users across the province and getting into separate contracts for network I don't think is the way to go. Q. And that's -- can you just expand upon that; why isn't it the way to go, because it's difficult to [Questioning] 763 Board Staff/Consultants determine the starting point? A. I think generally we haven't seen the need for contracts for a network type service. You establish a rate for the network and everybody is aware of what that network rate is and they can then make their decisions based on that information. MR. CURTIS: A. I think one of the other aspects, too, Susan, is that when you're talking about network, it's very, very difficult to attribute specific portions of the network to individual customers and to try and establish it on a contract basis I think would be one of the assumptions that one would be making, that you could, in fact, specify that this part of network serve that customer. The network, because of the way it acts, basically services all of the customers collectively and -- so the only, if you will, objective way of assigning costs out is on some sort of a pooled basis where you've pooled all of the network together. Q. Well, I agree that's true from a rate standpoint and you've done that by designing a pooled network rate, but I don't see why you couldn't somehow establish customer responsibility via some contracting method if there's so much of a discrepancy between use of NCP and use of CP. I'm hearing from you that you want to assure that customers can avoid their contributions and responsibility for recovery of the existing costs, but -- and, therefore, [Questioning] 764 Board Staff/Consultants you don't want to use CP. And NCP, you recognize you're giving up or customers are going to be sacrificing some diversity benefits. So couldn't do you this by contract? I mean, they're all paying a postage stamp rate but some contract level that could be based on some sort of historical measures or something like that? I still don't understand why that isn't a reasonable solution and I want to understand why that's not reasonable or possible. A. I guess again we're trying to, I guess, distinguish between network and connection and I think by and large when you're talking about connection facilities, you're talking about facilities that can be assigned to specific customers and -- so I think what we've talked about here is, going forward, that there would be contracts that would be formed with individual customers on their connection. The problem is I think associated with network and again, it's -- with an interconnected network, it's -- I think it's almost physically impossible to be able to attribute specific assets to individual customers. I guess what I'm struggling with is how you would see forming a contract between us and the customer to pay for specific network facilities or -- you know, if you can't say that a load customer uses "X" per cent of this particular transformer station over a course of a year, how can you actually form a contract with that customer? That's what I'm struggling with as far as your question. [Questioning] 765 Board Staff/Consultants Q. Well, I guess maybe I'm just trying to reconcile how a customer's charge is and I think that's what I've heard from the stakeholders, that it can vary so dramatically depending on whether you develop billing determinants based on NCP or based on CP. It's really just a billing determinant issue. And so if there's so much of a discrepancy because of the diversity of particular customers on the system, then is there an alternative to the both, to either of those options that would, you know, be, in effect, a compromise that would be workable? And what I'm hearing from you is that it would be impossible to come up with that alternative and you have to make a decision; is that fair? You couldn't ...? I'm really just referring to the billing determinants for network which, I think I'm hearing, is the biggest problem in terms of not allowing customers to maintain their diversity benefits. MR. PORAY: A. I think that's the key issue that we're dealing with here, and that is that in unbundling transmission from the current bundled rate which allows the diversity and going in order with a uniform transmission rate across the province, you are invariably going to end up with some customers that are going to be disadvantaged, if you like, or some customers -- or maybe not use that word, but there will be changes to the existing system; in other words, it's not possible to go with the status quo because today we have groups of customers, different classes of customers. [Questioning] 766 Board Staff/Consultants What we're trying to do here is to unbundle in the new realm transmission from everything else and treat anybody that accesses the transmission system on the same basis, through a uniform transmission rate. And that's essentially what other jurisdictions are doing as well in terms of access to the network, is to have a uniform transmission rate that's paid by somebody. Now, in terms of how do you then deal with diversity and coincident and non-coincident peak, as we said, we agree that there are a variety of ways that you can slice this and dice this. In our estimate as a starting position without having done a detailed analysis of the impacts, the non-coincident peak was the simplest because effectively, customers can trace their non-coincident peak and determine what their rates are and they can with some degree of certainty say that that rate will remain fairly stable. With coincident peak, to try to get over the ridership issue, you have to move away from the one-hour peak so people can't escape that and then the question is, well, do you establish 16 hours or do you establish a level between -- above which the peak is within 10 per cent of the system peak and ...? I mean, there are lots of issues that would have to be sorted out in order to come up with a more appropriate determinant that might capture some of the diversity, but it may not, in fact, capture all that's applicable today because -- by virtue of the fact that you [Questioning] 767 Board Staff/Consultants have separated transmission from .... Q. Yes, I certainly recognize that and appreciate your explanation and I understand simplicity in rates and administration is also a goal to this process as you've indicated earlier. I'm wondering, we've always pointed to other jurisdictions and they must have sort of struggled with this issue as well. Is there anything we can learn or anything that you came up with that either supports your current approach or suggests analysis would be required that we simply don't have the time for at this point? A. Well, I think analysis will be required anyway because -- I mean, in due respect, you should look at the impacts of the various ways of calculating the rates. Other jurisdictions have used combinations. I mean, there are some that use coincident peak. There are some that use non-coincident peak. So it tends to vary. Q. Let's just move off that. You indicated that in this transition period with respect to the connection projects, to the extent there is a -- any of those projects have a -- could potentially have a detrimental impact, i.e., increase that pool's connection charge, you would require a customer contribution. I'm just wondering why in this interim period you're not simply moving to a direct assignment of those connection projects. Why does this pooling have to be maintained at all in this interim period? Is there something that came [Questioning] 768 Board Staff/Consultants out of the MDC that said 'whenever open access occurs, that's the magic point at which we change our policy'? A. Well, I think in the interim period, Ontario Hydro certainly still has an obligation to its customers to connect those customers. In the new environment of open access, the emphasis shifts then to the customers. MR. CURTIS: A. I think it is based on our current legalistic accountability. We're still under the Power Corporations Act - at least in parts of it anyway - and until Bill 35 has been completely enacted, which it's our understanding that would occur at the date of open access, I think the dilemma that we're in is that we're under two pieces of legislation that direct us somewhat differently as far as this is concerned, so we're having to maintain the historic way of developing these until we're under the new legislative umbrella if you will. Q. Well, couldn't you still be the party that invests in these connection facilities, but couldn't you separately charge connection costs or develop customer-specific connection rates for these projects? MR. PORAY: A. I guess it's always possible, but we just felt that in the interim period, perhaps we should continue with what the current situation was. Q. So it's only when customers have an opportunity should they be subject to individual specific charges for a connection? Only when they have an opportunity to competitively procure connection services should they see those separate connection charges? [Questioning] 769 Board Staff/Consultants MR. CURTIS: A. Well, I think that point is clear. On open access, then customers can competitively seek, if they will, their own connection and we're talking about historically they weren't able to do that because they're constrained under the Power Corporations Act. And unfortunately, we've got this interim period where parts of PCA, Power Corporations Act, are being repealed as parts of Bill 35 are being introduced. And what we, I think, tend to be caught at, to some extent, by having to maintain historical practices until we're sure that we're free from the obligations contained under that. Q. Okay. I'm almost finished. You indicated that the IMO is going to be responsible for wheel in and wheel out and I just have one more question with respect to it, and customers will pay incremental charges for that which may be losses and potentially congestion charges. Can you give me any indication on the projected amount of congestion revenues that would be -- or connection costs that would be charged? To what amount, have you, Ontario Hydro, had to redispatch to meet individual load requirements? I just have no sense as to the amount of congestion that exists on the Ontario Hydro system. MR. PORAY: A. I think today it's a relatively uncongested system. The congestion costs could be, the cost of redispatch and marginal losses could be anywhere from sort of 5 to 10-million per year. [Questioning] 770 Board Staff/Consultants Q. Okay. To the extent -- and I recognize that congestion revenues were not something that is going to be captured for -- into a special pool, will they be credited back to you, the transmission rates in any way? Are there simply going -- either going to be winners and losers in the market in terms of when they pay congestion? A. The intent as far as the Market Design Committee is concerned, my understanding is, is that any revenues which would come from these wheel out and wheel through and the surplus that's available to the IMO will be credited back to the transmission providers to reduce their revenue requirement. Q. I think my final question for now. On page 197, I just want to be clear as to where -- how you came up to these determinants and whether they are historical or forecast. You make a reference on line 12 that the basis is the sum of the 1997 actual non-coincident peak load at each Ontario Hydro Services Company owned customer connection point. And then was it simply those connection points and then the forecast of load at those points? I wasn't -- I just couldn't follow where -- how the billing determinants were derived? A. Well, I think we had the data from 1997 and we just extrapolated it to 1999 and 2000 using the forecast. Q. Using growth rates? A. Yeah. Q. Okay. [Questioning] 771 Board Staff/Consultants MR. HARDY: That's it? MS. SIMMONS: Yes. MR. HARDY: Okay. I guess we'll go back to participants. Is there any, I guess -- oh. I'll go back to participants. I want to come back to the panel and see if there's any other additional information that we they wish to provide before we finalize, but why don't we start with you, sir. QUESTIONING BY THE PARTICIPANTS: MR. ROBERTSON: Thank you. Ed Robertson representing OCAP. Q. I just really want to come in on the last exchange between Board staff, Board staff consultant and the panel, which I summed up as the panel's explanation in regard to their inability to apply direct assessment of new connection costs is -- results from, in a sense, a legal situation. The sort of partial repeal of the PCA and the, as yet, not total introduction of the relevant sections of 35. In what fashion was this advice received by you? Did you have a legal opinion directly relevant to your problem as to what kind of -- what kind of assignment of costs you would make? If you do, I'd like to see it. MR. CURTIS: A. I think probably it's come from our own internal counsel and I don't know whether there's any -- are you asking for, like, a written opinion or... Q. Well, put it this way. You have, let's say [Questioning] 772 Participants in simpler terms, you have the choice of doing it one way or the other. Now, it's quite evident that there's a certain amount of support from the customers for doing it the other way. A. Right. Q. Did you ask, in fact, when you said to yourself how am I going to charge in this particular connection, is there any way in which we could do one or the other. I mean, what was the sort of impetus for relying upon some form of legal advice? In other words, did you get the legal advice and do it this way, or did you want to do it this way and get it supported by legal advice; put it that way? A. No, when the Act came out and was being discussed internally within the company, those -- that was the direction that we were taking at that point. Q. Well, is there any other peak? Is there any way you can actually give us some direct indication of the specifics of the advice you received in that connect? MR. HARDY: Sorry, if I could be clear, my understanding is that they are governed by the PCA up to a certain point, and is the question was there any formal or determination as to whether they should move away from the governance of the PCA in advance of knowing that Bill 35 would be coming in force. MR. ROBERTSON: Q. Actually, you've got one blind being rolled up and the other one being rolled down. I mean, where are they -- where are they in the interstice [Questioning] 773 Participants and it's the origin of the -- the origin of this determinant of that particular decision I'm interested in. MR. CURTIS: A. I guess I'm struggling with what you are seeking from us in terms of... Q. Well, I'll put it another way in the vernacular. It's chicken and egg. Did you start out with a chicken or was the egg provided for you? I just, you know, I mean, it's a common enough situation. Sometimes you don't ask the lawyers if you know the answer? A. Well, I again -- Q. Is this minuted anywhere? A. No, it isn't. MR. HARDY: It sounds like the answer is as simple as that, that I'm hearing that they are saying that they've continued with following the PCA. MR. ROBERTSON: Well, it's not as simple as that. The simple situation I'm trying to get at is there are people who are disputing this decision and they would like to be the possession of the same kind of information which led to the OHSC's view that they're not permitted to do this. That's all. MR. HARDY: I'll put it back to the panel then. MRS. FORMUSA: I don't know if I should jump into the fray or not, but let me try and help out here. My understanding of the interim period is that there are a number of rules to be worked out. And part of the rules include which portions of Bill 35 are to be proclaimed and which portions of the PCA will be repealed. [Questioning] 774 Participants Whether this all takes place magically on open access or most of it on April 1 is still to be determined. I think with respect to OHSC's decisions about what it will do in the interim period prior to open access, it's more, I think, not so much what the PCA is dictating or what Bill 35 is dictating as opposed to what kinds of historical responsibilities that Ontario Hydro has carried on will be carried on in the interim period. For instance, the obligation to connect, the obligation to supply, those kinds of responsibilities that will change on open access. And I think in fairness, a lot of those rules haven't been worked out. It's not as simple as saying they've decided which sections to proclaim and which sections not to proclaim. There's more than what's in the PCA that kind of comes -- it's more baggage that comes along with these entities during this transition period than is actually in the legislation. So I don't know if I've helped clarify it, but it's not as clear cut as saying the legislation says this and we must do that. It's a larger historical package and not all the rules of this transition period have been worked out. I think that's as far as we can go and we are trying to predict how -- we are trying to give you our views of what would be appropriate to do during this period assuming we continue with these historical obligations. [Questioning] 775 Participants MR. ROBERTSON: That's fair enough. I quite understand the answer, but the answer, if I can summarize it, is that the quick sections of various bits of legislation are in existence, is quite irrelevant. I mean, the answer indicates to me that OHSC has taken a view that they have a continuing obligation to carry on with these historical obligations and that's their -- that's their justification for this particular choice until such times as open access comes along; is that fair? MRS. FORMUSA: That's my understanding of it. I don't know if David -- MR. CURTIS: Sure. MRS. FORMUSA: -- disagrees. MR. CURTIS: No, that's -- MRS. FORMUSA: I hope not. MR. CURTIS: No, I don't disagree. MR. ROBERTSON: Thank you. MR. HARDY: Okay. Thank you. Are there other questions? Bruce? MR. BACON: Just one more. Bruce Bacon for OCAP. Q. As we move, you know, it's down the road, I understand that, but as we move into locational marginal pricing, will this structure hold together, this structure to reposing hold together on a locational marginal pricing or will it have to be adjusted again. MR. PORAY: A. I think when it comes to transmission pricing, you have to separate certain [Questioning] 776 Participants important factors. This rate order deals with the recovery of embedded costs. Locational marginal pricing has nothing to do with the recovery of embedded costs. It is the usage of the transmission system which is priced on an energy basis. And today, the usage of the transmission system is essentially calculated by the CMO as an average uplift which is -- and this is the cost of redispatch and losses, calculated across all customers in Ontario and charged accordingly. In the interim -- in the initial -- sorry, in the initial stages of the open market where there will be no locational marginal pricing, the IMO will do precisely that. It will calculate what is the cost of redispatch, it will calculate the losses, average them out, and charge them to the customers. What we are dealing with that -- what these -- these components are really the usage of the transmission system, not the provision of the infrastructure. The rates that we're dealing with here are the rates for the provision of the infrastructure. MR. HARDY: Thank you. Are there other questions? Other questions from our Panel or Board Staff? QUESTIONING BY BOARD STAFF AND CONSULTANTS: MS. WALLI (Board Staff): Yes. Just two final questions on closing. Q. Firstly, I'm referring back to the activity based costing study that was done for Ottawa district in [Questioning] 777 Board Staff/Consultants 1996 which you then used to extrapolate a system wide, essentially. Did you use this study effectively because it was available or are there some specific reasons why the Ottawa district is representative of the province wide system. MR. PORAY: A. I'm not clear what the decisions, what the underlying decisions were made to chose the Ottawa district as the district for the ABC study. But at the time when this study was undertaken, there was a general direction to move towards activity based cost management and activity based costing. And we used, essentially, the results of that study because we felt that this was the best information that we had. But the full assumptions of why the Ottawa district was chosen, I'm not clear of those. Q. Were there other activity based costing studies done at that time or was it strictly Ottawa district? A. My understanding is it was strictly the Ottawa district. Q. So from that point of view, you have nothing to test or benchmark against on the Ottawa side? A. Not within Ontario Hydro. And I guess, we won't have until these service level agreements will come in which -- which really will be the next level of evolution. Q. Thank you. And just one final question. Does OHSC intend to provide a draft rate order as [Questioning] 778 Board Staff/Consultants part of this filing that would include, for example, the usual attached schedules including all the conditions as well. For example, customer attach -- the customers attaching providing demand forecast, et cetera. I think that was detailed on page 195. A. Sorry, what was your question? Sorry. Q. Essentially does OHSC intend to provide a draft rate order for the Board's use? A. Other than what we've done here in terms of providing terms and conditions of service and... Q. That's correct. Essentially a document that could potentially look like the final rate order? MRS. FORMUSA: Kirsten, if I could help out in that regard. When we were preparing the application we thought about that, but there's still, I guess in our minds, we still had the work out the relationship between the licence and the rate order and so we weren't sure -- I think the licence comes first and it can make reference to things in the rate order. So it can certainly -- we can certainly do that, but we weren't quite sure of the timing of and the integration between the licence and the rate order itself. So we'd be prepared to do it with guidance probably. I guess it's a bit of a new ball game and so it's certainly possible to do. MS. WALLI: Actually, that would be wonderful. So fair enough, we could perhaps have some further [Questioning] 779 Board Staff/Consultants discussions on that. MRS. FORMUSA: I that would be helpful and we would appreciate some guidance because I'm not quite sure how it does fit in with the licence. MS. WALLI: That's fair enough. Thank you. MR. HARDY: Okay. Thank you. Panel, is there anything that you wish to add or contribute before we -- I think we are going to be closing off very soon? MR. SNELSON: I have other questions. MR. HARDY: Okay. Let's deal with those questions. MR. SNELSON: They will probably go until after lunch. MR. HARDY: Okay. How long do you think you will be, Ken? MR. SNELSON: I'll be at least half an hour and maybe more. MR. HARDY: Are there other questions as well? ---(No response) MR. SNELSON: I have one question I would like to ask, if you think you are breaking for lunch, that is a follow-up to one of the recent discussions. MR. HARDY: Certainly I will entertain that, but I'm wondering if we could continue now and make it a long morning and -- MR. SNELSON: Okay. MS. WALLI: Can we take a five-minute break? [Questioning] 780 Participants MR. HARDY: Why don't we work through. Again, we're informal. If anybody needs to walk out or walk in, that's fine with me. Ken, why don't we start. We will try to go to 12:30, 12:40 and call it a long morning, okay. QUESTIONING BY THE PARTICIPANTS: MR. SNELSON (AMPCO): Okay. Q. The follow-up question is to the one about the effective locational marginal pricing and when locational marginal pricing is introduced, then I believe that the IMO may very well collect a surplus because of the congestion rents of the transmission lines and because the locational marginal pricing scheme tends to charge for incremental losses rather than average losses. Can you confirm that? MR. PORAY: A. Yes. Q. And the intent I believe should be that if the IMO collects a surplus, then it should be returned to the transmission company to reduce the transmission revenue requirement? A. It's possible, yes. Q. Okay. I just wanted to get that clear. Moving on to my third questions -- MR. HARPER: Dave, excuse me. I think the panel, if we are going to run for an extended morning, would appreciate a five-minute break at this point in time, as has been suggested, if that was okay? MR. SNELSON: That's fine with me. [Questioning] 781 Participants MR. HARPER: Then we can wrap up the morning. MR. HARDY: Why don't we break for five minutes then. I feel others are a bit antsy as well. So we will be back at about 12:20. ---Recessed at 12:15 a.m. ---On resuming at 12:20 p.m. MR. HARDY: I would like to begin. I know I asked before we broke, asked the panel if they had anything to add. I know they do now. Ken, I understand that you will be about half an hour or so. MR. SNELSON: I would think it would be at least half an hour. MR. HARDY: Okay. So we'll take it up to one o'clock. We will assume we will be breaking around there. Certainly if there are other questions we will entertain those as well. Let's start with the panel. If you can just add the information that you wish and then we'll move back to Ken. Go ahead, please. MR. PORAY: Thank you, Dave. It appears at that yesterday's Market Design Committee meeting regarding settlements that any surpluses which the IMO will recover from the marketplace will not go directly towards reducing the transmission revenue requirement, but rather go towards reducing the uplift. That seems to be the position or the direction that the MDC is making. MR. HARDY: Thank you. [Questioning] 782 Participants MR. PORAY: I just thought it should be clarified. MR. HARDY: Thank you. Ken, why don't we then resume with your questions, please. MR. SNELSON: Okay. I just want to follow up on that. Q. That is this is that that sounds very reasonable during the period when before locational marginal pricing is introduced, but I believe the situation after locational marginal pricing is still likely to be -- uplift is greatly reduced because constrained off payments are no longer required and so on. So there may still be a surplus to be distributed through the transmission rate? MR. PORAY: A. It's possible, Ken, yes. Q. Okay. If you turn to page 187 of the submission, at the top of the page, one of the principles for the rate structure design is that transmission charges should be designed to be non-bypassable to the maximum extent. And I presume that the reason for this is that it's to ensure that customers of the transmission system pay for the facilities that were built to serve them and that they can't escape paying for that by building their own generation. Is that one of the reasons for that? A. Yes. Q. It seems to me, and you have mentioned it [Questioning] 783 Participants this morning, this is actually a smaller part of a more general principle which is that rates should reflect cost causality to the greatest extent possible. Would you agree that's a reasonable rate principle and this is a kind of a subset of that? A. I think that's the general direction, yes. Q. Okay. And your principles do not address consistency with past practice and continuity with existing methods of charging transmission. Would these be reasonable principles to add? A. I think we envisage this as moving forward from where we are today. So we wouldn't necessarily be adopting the same principles that are adopted today in the pricing of transmission. Q. Okay. I wanted to turn now to the effects on a number of classes of customer of the new transmission rate. And the first one I wanted to talk about was the surplus power customers. Have you considered providing a transmission rate different to the one proposed here for customers who currently take surplus power? A. No, we are not proposing to charge surplus power customers because in today's rates they don't pay for transmission system. They are effectively taken advantage of surplus generation capacity on the system. Q. Okay. And I recognize the conditions and one of the conditions under which these customers are supplied is that they will only be supplied from surplus generating [Questioning] 784 Participants capacity and surplus transmission capacity. New transmission capacity was not -- has not been built and will not be built to support them. How is it on the new scheme they will pay transmission rates the same as everybody else? How is that consistent with cost causality to make them pay a full transmission rate when no transmission capacity has been built to serve them? A. My consideration in this respect, Ken, is that surplus power customers don't contribute costs -- don't contribute anything towards the cost of the transmission system today. As to what happens in the future, I don't know how that class of customers will be treated. Q. Okay. Let's move on to customers who have their own generation. Let's consider a customer who has his own generation today to supply part of his load. In the new rate structure that you are proposing, how would you determine the billing demand of an existing customer who owns some generation? A. The customer would be billed on their monthly -- past month's demand and I think the general perspective is, again, this is a direction that came out of the MDC, that current customers who own their own generation would be billed on the net demand, that that generation would be grandfathered. Q. Okay. Do you propose to offer a customer with his own generation, an existing customer with his own [Questioning] 785 Participants generation any form of back-up transmission service? A. We were not considering offering any specific or any different service called back-up service. We were considering if there is capacity on the transmission system to accommodate the customers' additional megawatt demand, then they would be billed essentially on what they took for that particular month when they required it. Q. So if their demand is higher on one day in the month because their generator out of service on either a planned or forced basis, they would pay the transmission charge for the whole month? A. Yes, they would be billed on the past month's demand. Q. I'm sure you are aware that in the existing rate structure there are a number of different degrees of back-up service with different levels of associated transmission service. Supplementary and economy back-up are like surplus power, they are only supplied if surplus transmission capacity exists and new transmission would not be built to support their back-up needs. Why should supplementary and economy back-up customers pay a full transmission charge to pay for an existing transmission system that was not built to meet their needs? A. An existing customer who has generation is taking power from the system. So they are making use of [Questioning] 786 Participants the system. Q. But these customers are supplied on the basis that there is surplus transmission capacity available and if the capacity is not available, then they are not supplied? A. We are talking about a customer who owns their own generation? Q. Yes. A. Not a surplus customer, but a customer who owns their own generation and, therefore, they -- Q. And buys either supplementary or economy back-up service. A. Okay. So what we are saying is in our rate that customer would be billed on the basis of their net demand. And for those times of the year when their generation goes down, they would be billed on whatever demand was metered for that particular period. Q. So, for instance, let's just say for sake of example that their generation failed one day each month, they would pay the same transmission charges if they took power on a continuous basis? A. In accordance with the monthly billing yes. MR. HARDY: I think I've heard the question posed three times now and three answers, so... MR. SNELSON: Okay. I will leave the question about long-term back-up service just in the interest of shortening it. Q. If we move on to embedded generation that is [Questioning] 787 Participants new, how would the coincident peak demand -- sorry, the non-coincident peak demand of a customer who installs generation in his own plant to meet part of his load be determined? A. I think the general direction is that any new generation that is installed would be -- the customer demand would be billed on the gross load. Q. And how would you determine the gross load? A. The peak demand of the customer without the generation -- without the new generation. Q. So would you have put a meter on his generation and do a sum of the-- A. Yes. Q. --meters from his generation and from the system and the find the peak of that? A. Yes. Q. Let's assume we have a customer who was taking 50 megawatts and he installs 20 megawatts of generation. Let's assume for this discussion that he doesn't need back-up supply and he's willing to reduce his demand to the 30 megawatt level if his 20 megawatt generator fails. So now he is taking 30 megawatts from the system. I presume that I am right that he will now pay for 50 megawatts of transmission service for the indefinite future even though he's now only taking 30 megawatts from the system? A. That's correct. [Questioning] 788 Participants Q. Let's look at another example. This is a customer who is currently taking 50 megawatts and expands his plant to use another 20 megawatts and at the same time he installs 20 megawatts of generation. Again, for simplicity let's assume he doesn't need back-up service. Am I right that in this new rate he will be charged for 70 megawatts of transmission service which is the sum of his generation and his load. A. I think the general perspective is the customer should not escape charging for his portion of the transmission cost. And I think the direction would be to charge them on the basis of 50 megawatts. Q. Is that written down anywhere in these applications as to how that will be done? A. I don't believe it is, no. Q. Coming back to another point on the issue of diversity, appendix S to the original submission is, I believe, largely extracts of draft documents that were prepared as part of the technical panel process for the MDC. A. Yes. Q. And on pages 144 and 145, there is a bullet that starts at the bottom of the page which says that some panel members believe that there is an advantage of the coincident peak methodology in that otherwise exactly similar customers would attract the same transmission service charges whether they're connected directly to the transmission system or via the LDC. [Questioning] 789 Participants Do you see that bullet? A. Mm-hmm. Q. Now, I think you will agree that after this draft was prepared, we had some discussions and that that document was changed for the purposes of the MDC to remove the part starting "OHSC is of the opinion that the opposite may be true" and then the reasons that follow and that was replaced by a qualifier that the original statement is true provided that the charges -- sorry, provided that the LDCs agree to pass on the transmission charges at the retail level in the same form as at the wholesale level. A. Yes, that is quite true, Ken. Q. With that qualification, OHSC has withdrawn that particular objection to coincident peak billing? A. No, I don't think we have because in the general discussion we said that there should be -- at the MDC, that there are alternative methods of doing this calculation of the rates whether you use coincident or non-coincident and we felt that before you could really make a decision, you had to do a full analysis of the impacts. Q. But you're prepared to bring forward this proposal without having done a full analysis of the impacts? A. I think as a starting point, yes. I mean, it's a evolutionary process. We're moving in stages towards open access and we felt in the space of time and [Questioning] 790 Participants within the given circumstances, that this was an appropriate point to start with, yes. Q. But my point about this particular bullet is that the bullet makes the point that with coincident peak methodology, then it is possible to pass the charges on in the same form to customers who are connected via an LDC provided the LDC uses the same form to pass on -- the same rate form to pass on the transmission charge. And the reason I'm making quite an issue of this is, I believe this is important for embedded wholesale market participants at the -- at one of the sessions where Mr. Stewart was here, he said that embedded wholesale market participants - that is, large industrial customers who are fed through distribution systems or municipal utilities that are fed through distribution systems - would have the choice of being billed for their transmission on a direct basis or on a basis through their LDC. And this feature of coincident peak billing reduces the incentive to embed yourself in the LDC by -- and capture the diversity benefits of being embedded in the LDC which comes with the non-coincident peak methodology. Now, do you agree with that or maybe I should -- we'll just move on? A. I mean, I can share your concern. I think that -- I think we should move on. I think there are other ways, as I say, of dealing with this. In an evolutionary process, it's quite possible that we may move to a different rate design in a later stage. [Questioning] 791 Participants Q. Okay. Now, let's move on to some other jurisdictions. And on page 193 of the main submission, around line 9, you say: 'In general, the proposals contained in this application are also consistent with the practices in other jurisdictions in the United States and overseas.' And the next paragraph refers to the network service rate recommended by the FERC for the United States' jurisdictions. And I have the pro forma network integration service transmission tariff for the FERC and I can just read a piece here, which says that: 'The transmission customers' monthly network load is the hourly load of the transmission customer coincident with the peak of the transmission provider's transmission system.' And I'm wondering if you're sufficiently familiar with the FERC tariff to confirm that that implies a coincident peak methodology. A. I believe that FERC does use coincident peak methodology, but I think also in terms of the network tariff under FERC, that it is -- essentially it's not a predetermined rate, that it is an allocation methodology whereby the transmission provider identifies what their transmission revenue requirement is. It's then assigned on a monthly basis, whether it's divided by 12 or whatever the case may be, and -- so that for a particular month, [Questioning] 792 Participants that is the transmission revenue which they have to recover from their customers. In addition, the entity may offer a point-to-point service for which there will be a rate, a predetermined rate. And what actually happens is, at the end of the month, a calculation is made based on how much of the point-to-point service was taken. The revenue from that is then subtracted from the revenue requirement identified for the monthly revenue requirement and billed to the load customer in the ratio of their load demand. So it's not a rate per se that is similar to a predetermined rate. It's sort of an allocation of the cost. But I agree, yes, it does use coincident peak. Q. Okay. And would you also agree that the National Grid Company in England uses a coincident peak methodology? A. Yes, they do. Q. And I have some information that appears to indicate that Norway also does. I believe you -- A. If I may just interject, my understanding is that in New Zealand and in Australia, they use non-coincident peak methodology. Q. That may be. And that you -- I believe you mentioned in your own discussion that there were -- previously today that there are some jurisdictions who use coincident peak and some who use non-coincident peak? A. (Nods) Q. Okay. I had one question here which I had [Questioning] 793 Participants expected Susan Frank to be part of the panel and I don't see her here today. I'll ask the question, but if you want to defer on it, then that would be a reasonable thing to do, and this refers to appendix L. This is appendix L of the original submission on page 121 and it relates to the shared function service that is identified in that table as business development. And the description of business development is 'evaluation of current and potential business ventures to grow OHSC and manage the launch of new initiatives'. And if you look over on page 120, business development appears to be $5-million. And also on appendix L, page 120 -- maybe I've got the wrong reference. Okay. It's page -- oh, page 123, okay? It's on page 123. Step 2 near the top of the page, it says: 'Those corporation functions judged to be caused by or of benefit to the shareholder were retained at the OHSC holding company level to be funded by dividends.' And the description of the business development sounds to me like the sort of thing which is to grow OHSC and to manage the launch of new initiatives. It doesn't sound to me as though it's appropriate to be included in the revenue requirement of the regulated company. And the question is: Is that business development activity included in the revenues being sought to be recovered through this process? MR. CURTIS: A. My understanding, Ken, and I [Questioning] 794 Participants think it will be subject to confirmation, is that it would not be included in the transmission company revenue requirement. That hundred and -- for example, if you go back to page 120 where it talks about the total for OHSC functions and services summary, that at the bottom there, it talks about 136.9-million for 1999 and 120-million for 2000. I think -- Q. 129-million. A. I'm sorry, 129-million for 2000. I think if you went back to the discussions that went on in panel 1, that you would find that these costs were taken through the steps that were identified on page 122 and 123. And I believe .... MR. HARPER: Dave, if I could perhaps help here. Ken, if you look at appendix G of the December 23rd filing, page 16, you'll see an indication of the various costs. And at the very bottom of the page, you have functions and services not allocated in the very bottom item there. 5.2 is business development which shows that it's not part of the costs that were allocated to the business units. MR. SNELSON: Okay. That's helpful. Thank you. Those are my questions. MR. HARDY: Are there any other questions that have arisen as a result of Ken's questions and also the responses of the panel? ---(No response). [Questioning] 795 Participants Has everybody had an opportunity to ask questions of this panel that they wish to? (No response). I don't see anybody requesting to ask additional questions on that. I'd like to thank this panel for their participation today and we start of tomorrow -- sorry, Bruce? MR. BACON: It's not a question for the panel. It's a question as we proceed into distribution panels tomorrow and Thursday. I think Susan asked OHSC in that first panel for information with regards to revenue. Specifically, it could be 1998 revenue for OHSC distribution or it could be revenue at existing rates. That's a rate term. But taking the rates and multiplying by the revenue -- or multiplying by the volume and coming up with a revenue projection for distribution, I think that would be information that we need to move -- it would be good information to have as we go into the distribution section of the application. I'm just wondering, has OHSC put that together yet or will we have that by ...? MR. HARPER: All I can say is, we've been working on it and we'll do our best to have it. I think the OM&A which is in the revenue requirement, the second panel which is on Thursday, and we'll do our best to get it before then or on that day. MR. HARDY: Okay. You'll make sure -- you'll be 796 here tomorrow? MR. BACON: Yes, I'll be here tomorrow and Thursday as well. MR. HARDY: Okay. So -- MR. BACON: I think it's important information to have. And I guess if we don't have, we may have to estimate what it is potentially. MR. HARDY: Okay. So we'll make sure we bring that up tomorrow then. Again, I'd like to thank the panel for their information and tomorrow we start then with distribution assets and capital plans. We're adjourned. ---Whereupon, the Technical Conference proceedings were adjourned at 12:49 p.m., to be reconvened on Wednesday, January 20, 1999, at 9:00 a.m. 797 I N D E X o f P R O C E E D I N G S Page No. Overview (Facilitator) 681 Introductions SERVCO panel 681-682 Response to yesterday's questions by the SERVCO panel 682-684 PRESENTATION: by Andy Poray 684-699 QUESTIONING: by Board Staff and Consultants 699-726 by Participants 726-738 by Board Staff and Consultants 739-745 by Participants 746-759 by Board Staff and Consultants 759-770 by Participants 771-776 by Board Staff and Consultants 776-779 by Participants 780-795 Parties who questioned: B. Bacon E. Robertson . . . . . . . . . OCAP R. Stephenson . . . . . . . . Power Workers' Union K. Snelson M. Angemeer . . . . . . . . . Hydro Mississauga JB/MC/LL [ Copyright 1985].