2657 1 RP-1999-0044 2 3 THE ONTARIO ENERGY BOARD 4 5 IN THE MATTER OF the Ontario Energy Board Act, 1998; 6 7 AND IN THE MATTER OF an Application by Ontario Hydro 8 Networks Company Inc., for an Order or Orders approving 9 year 2000 transmission cost allocation and rate design. 10 11 12 B E F O R E : 13 R.M. HIGGIN Presiding Member 14 P. VLAHOS Member 15 B. SMITH Member 16 17 18 Hearing held at: 19 2300 Yonge Street, 25th Floor, Hearing Room No. 2 20 Toronto, Ontario on Monday, March 6, 2000, 21 commencing at 0932 22 23 24 25 HEARING 26 27 VOLUME 14 28 Les Services StenoTran Services Inc. 613-521-0703 2658 1 APPEARANCES 2 JENNIFER LEA/ Counsel to Board Staff 3 MICHAEL LYLE/ 4 5 HAROLD THIESSEN/ Board Staff 6 NABIH MIKHAIL/ 7 COLIN SCHUCK/ 8 KATHI LITT 9 10 DONALD ROGERS/ Ontario Hydro Networks 11 BRYAN BOYCE Company Inc. (OHNC) 12 13 DAVID BROWN Independent Power Producers 14 Society of Ontario (IPPSO); 15 Ontario Natural Gas 16 Association (ONGA) 17 18 JAMES FISHER/ Association of Major Power 19 KEN SNELSON Consumers in Ontario (AMPCO) 20 21 MICHAEL JANIGAN Vulnerable Energy Consumers 22 Coalition (VECC) 23 24 ROBERT WARREN Consumers Association of 25 Canada (CAC) 26 27 28 Les Services StenoTran Services Inc. 613-521-0703 2659 1 APPEARANCES (Cont'd) 2 BRUCE CAMPBELL/ Ontario Power Generation 3 JOEL SINGER/ (OPG) 4 JOHN RATTRAY 5 6 LLOYD GREENSPOON NorthWatch 7 8 DAVID POCH Green Energy Coalition (GEC) 9 10 MARK MATTSON/ Energy Probe 11 MIKE HILSON/ 12 TOM ADAMS 13 14 PETER BUDD TransAlta Energy 15 16 MURRAY KLIPPENSTEIN/ Pollution Probe 17 JOANNA BIRENBAUM 18 19 RICHARD STEPHENSON Power Workers Union 20 21 MARK RODGER Toronto Hydro Electric 22 System Ltd. 23 24 PAUL DUMARESQ Ontario Association of Physical 25 Plant Administrators 26 27 SHARON WONG Imperial Oil Ltd. 28 Les Services StenoTran Services Inc. 613-521-0703 2660 1 APPEARANCES (Cont'd) 2 ERIK GOLDSILVER Electrical Contractors 3 Association of the Ontario; 4 Collingwood Public Utilities 5 Commission 6 7 ROGER WHITE Energy Cost Management Inc. 8 9 RICHARD KING Five Nations Energy Inc.; 10 Detroit Edison Co. 11 12 KENNETH LIDDON Suncor Energy Inc. 13 14 GEORGE VEGH/ Amoco Canada (BP Amoco); 15 JEAN-PAUL DESROCHERS Toromont Energy 16 17 KEITH RAWSON/ TransCanada Energy 18 BONNIE ANDRIACHUK 19 20 PAUL VOGEL/ The Chiefs of Ontario 21 CAROL GODBY 22 23 ALAN MARK/ Municipal Electrical 24 KELLY FRIEDMAN/ Association (MEA) 25 MAURICE TUCCI 26 27 28 Les Services StenoTran Services Inc. 613-521-0703 2661 1 APPEARANCES (Cont'd) 2 WENDY EARLE/ Brampton Hydro, Cambridge 3 JAMIE SIDLOFSKY and North Dumfries Hydro, 4 Guelph Hydro, Niagara Falls 5 Hydro, Oakville Hydro, 6 Richmond Hill Hydro, 7 Pickering Hydro and Waterloo 8 North Hydro 9 10 RICK COBURN INCO Limited; Ontario Mining 11 Association 12 13 TED COWAN Ontario Federation of 14 Agriculture 15 16 ALECK DADSON Enron Capital Corp. 17 18 19 20 21 22 23 24 25 26 27 28 Les Services StenoTran Services Inc. 613-521-0703 2662 1 Toronto, Ontario 2 --- Upon resuming on Monday, March 6, 2000 3 at 0932 4 THE PRESIDING MEMBER: Thank you. Please be 5 seated. 6 Are there any preliminary matters at all? 7 Mr. Rogers. 8 PRELIMINARY MATTERS 9 MR. ROGERS: Yes, sir. Thank you. 10 This morning I am in a position to file a 11 document entitled, "Implementation of Transmission 12 Rates", which we have talked about, which is an outline 13 for the Board, in summary form, of what we are asking 14 the Board to approve in this case, more specifically, a 15 rate to go into effect on November 1, and some other 16 ancillary processes that are going on and how they 17 relate to this process. 18 THE PRESIDING MEMBER: Okay. 19 MR. ROGERS: There are copies available for 20 distribution. I will have a witness -- Dr. Poray can 21 speak to this tomorrow. 22 THE PRESIDING MEMBER: Okay. Thank you. 23 Any other preliminary matters at all? No. 24 All right. Good morning. How are you? 25 MR. WONG: Good morning. 26 THE PRESIDING MEMBER: Dr. Wong, is it or 27 is -- 28 MR. WONG: Mister. Les Services StenoTran Services Inc. 613-521-0703 2663 Preliminary Matters 1 THE PRESIDING MEMBER: Mister. Okay. Would 2 you like to come and swear in for a start and then we 3 will begin. 4 SWORN: HAROLD WONG 5 THE PRESIDING MEMBER: Good morning. 6 Would you like to start and just give us a 7 background, we have read the evidence, if you could. 8 Thank you. 9 EVIDENCE-IN-CHIEF 10 MR. WONG: Good morning. My name is Harold 11 Wong. I am President of EnergyLink Power Corporation. 12 I have filed my CV with the Board and I have sent copies 13 to all the intervenors and OHNC. 14 EnergyLink Power Corporation is a power 15 project development company involved with the 16 development of small embedded generation projects in 17 Ontario. 18 I prepared the EnergyLink prefiled evidence 19 with the Board. The reference for that is Exhibit H, 20 Tab 15, Schedule 1, as well as the clarification letter, 21 Tables 5B and 5C, which I filed with the Board on 22 February 23rd. There are extra copies of it over by the 23 window ledge there. I developed all this evidence for 24 the purpose of this hearing. 25 MR. LYLE: We will mark that as Exhibit G14.1, 26 Mr. Wong. 27 EXHIBIT NO. G14.1: Covering letter, 28 dated February 23, 2000, with Table 5B, Les Services StenoTran Services Inc. 613-521-0703 2664 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 Table 5C and curriculum vitae of Harold 2 Wong attached 3 MR. WONG: My friends at IPPSO have already 4 covered the broader issues and arguments respecting all 5 embedded generation projects. I would like to focus in 6 on a subset of embedded generation which we have called 7 small embedded generation or SEG projects, S-E-G, and 8 elaborate on the net versus gross load billing issue. 9 I am concerned about the characterization by 10 others that net load billing for even SEG projects would 11 be considered a subsidy or an exemption or a distortion 12 in the marketplace. 13 There are two key factors respecting SEG 14 projects which I feel are very relevant to the current 15 arguments on net load billing versus gross: first, the 16 location of SEG projects; and, secondly, the forecasted 17 capacity addition. 18 So, first, with location, small embedded 19 generation projects are distinguished from other 20 embedded generation projects and large merchant 21 generators because they are located at the end of the 22 electricity delivery system. 23 SEG projects are located on site with the 24 end-use customer and connected directly to the customer. 25 SEG projects are connected to the distribution system 26 for sale of any excess electricity, all with little or 27 no use of the transmission system. 28 SEG projects are located at the consuming end Les Services StenoTran Services Inc. 613-521-0703 2665 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 of the electricity transportation infrastructure, while 2 merchant plants, such as OPGI's plants, are on the other 3 end, the supply end. 4 So SEG projects are located further down the 5 supply chain and should not have to compete on the same 6 basis with merchant plants at the top end of the supply 7 chain. 8 Normally in most businesses, close proximity 9 between supply and consumption of products would result 10 in an economic advantage. There is a close analogy in 11 the natural gas business. There are large pools of 12 natural gas in Alberta and large suppliers of natural 13 gas in Alberta analogous to the large merchant 14 electricity generators. These large high-pressure 15 pipelines transport the gas from the producing region to 16 Ontario similar to high voltage transmission lines 17 carrying large quantities of electricity to the 18 consuming regions. 19 Then the local LDC, such as Enbridge or Union, 20 further transports the gas at low pressures to the final 21 consumer, as does the MEUs at a distribution voltage 22 level for electricity. 23 Natural gas losses due to transportation are 24 in the order of 8 per cent whereas electricity line 25 losses range between 7 to 9 per cent at the distribution 26 level. 27 A small natural gas field in southwestern 28 Ontario costs more to develop and to operate due to its Les Services StenoTran Services Inc. 613-521-0703 2666 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 smaller pool size than larger pools in Alberta as does 2 SEG projects compared to merchant plants. But the 3 Ontario pools are desirable because of its location. It 4 provides reliability to the consuming regions should 5 outages occur on any leg of the transportation system or 6 the transmission system in electricity. There are also 7 significant savings in transportation losses. 8 Reduction from small gas pools in Ontario are 9 easily absorbed in the load growth within Ontario. In 10 the natural gas business, the Ontario source of supply 11 enjoys the Ontario avoided price either to the end 12 connected user or avoided price at the TCPL-LDC 13 interface. 14 Charging a SEG project, a portion of the 15 transmission system cost is like trying to charge the 16 Ontario gas producer a portion of the TCPL 17 transportation costs. It is not equitable nor fair. It 18 is not done in the natural gas business or in any of the 19 energy businesses, and it would contravene normal 20 business practices in general. 21 There is an inherent advantage of locating an 22 energy supply source close to the consuming area. This 23 advantage should not be eroded by charging SEG projects 24 for transmission services it doesn't use. 25 OHNC and OPGI's predecessor company, Ontario 26 Hydro, also recognized that generation projects 27 delivered to different points down the delivery chain 28 have different values. Les Services StenoTran Services Inc. 613-521-0703 2667 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 Exhibit F9.1, which shows tables of 2 incremental system values of power and energy 3 illustrate, on page 7, that if a new generation plant 4 had a delivery point on the distribution level it would 5 avoid inter-area transmission, bulk transmission, 6 regional transmission, and distribution costs. 7 The further up the supply chain, the less 8 benefit or avoided cost for Ontario Hydro. New 9 generation delivered to the 230 kV high-voltage system 10 further upstream from the consumer receives only bulk 11 transmission and inter-area transmission avoided cost 12 benefits. 13 Ontario Hydro recognized that a merchant 14 generator's price, when the merchant generator is 15 connected to the transmission voltage level, should have 16 additional transmission costs added to its price before 17 comparing it with a small embedded generator's price, 18 which is connected to the distribution voltage level. 19 In fact, that same reference on page 8 provides an 20 illustrative calculation for a SEG project. 21 This is the equitable formula and level 22 playing field for competition between merchant and SEG 23 projects. Having the SEG project incur transmission 24 costs as proposed by OHNC or by any amount of gross load 25 billing would be contrary to fair competition. 26 There are a number of SEG projects that exist 27 in Ontario and I would like to just mention them to you 28 to give you an idea of where they are located, because I Les Services StenoTran Services Inc. 613-521-0703 2668 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 think that is quite an important aspect of how costs may 2 be shifted between customer groups. 3 Examples of SEG projects are: 4 The Heinz 7-megawatt plant in Leamington that 5 is connected to the Leamington PUC. This project would 6 belong to the customer group of other MEUs. 7 There is the Labatt's 4.7-megawatt plant in 8 London which is connected to the customer group of the 9 largest 10 MEUs. 10 Brock University. 6.6 megawatts. Other MEUs. 11 The University of Toronto. York University. 12 These are both connected to the customer group of the 13 largest 10 MEUs. 14 The National Research Council, in Ottawa, is a 15 4-megawatt plant connected to largest 10 MEUs. 16 Casco, in London. A 20-megawatt project. 17 Largest 10 MEUs. 18 Casco, at Port Coburn. I think this is direct 19 or other MEU, I am not certain which one. 20 Hiram Walker, in Windsor. A 7-megawatt plant, 21 connected to the largest 10 MEUs. 22 Sunoco, at Brantford. 4-megawatt. That is 23 connected to a small PUC other MEU customer group. 24 University of Windsor. Four megawatts, 25 connected to one of the large 10 MEUs. 26 The SEG projects could be located in all 27 customer groups but, in the past, most of them have been 28 located within LDCs, large and small. Les Services StenoTran Services Inc. 613-521-0703 2669 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 So I would like to highlight how this is 2 relevant to cost shifting. 3 Cost shifting due to embedded generation 4 occurs when there is a different distribution of 5 embedded generation between the customer groups than 6 OHNC's reference distribution of loads between customer 7 groups. 8 So this is pretty clear in their CD, which is 9 Exhibit E-1.12, where OHNC's reference distribution of 10 load was based on the 1997 average monthly 11 non-coincident demand, -- and that gave a distribution 12 of about 42 per cent to the largest 10 MEU group; about 13 44 per cent to the other MEU group; about 9 per cent to 14 the 20 direct-connect customer group; and about 6 per 15 cent to the other direct-connect customer group. 16 So if embedded generation distribution is the 17 same as the load distribution, even for much higher 18 levels of embedded generation, there would be no cost 19 shifting. 20 All of the impact assessment cases modelled by 21 OHNC for cogeneration -- this would be their options, 3, 22 4A, 4B, 4C, all in Exhibit D5.2 -- assumed a 75/25 per 23 cent distribution of cogeneration between large and 24 other direct-connect customers and zero to the MEUs. 25 The direct-connect customer group, therefore, received a 26 decline in costs, while the MEUs got the increases. SEG 27 projects located within the MEUs will reduce the cost 28 shifting to the MEUs. Les Services StenoTran Services Inc. 613-521-0703 2670 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 The second factor that I wanted to raise was 2 SEG capacity. 3 EnergyLink has estimated that about 540 4 megawatts in our middle case of cumulative SEG capacity 5 may be added by the Year 2008, if net load billing was 6 granted for this segment of projects. 7 AGRA Monenco, in OHNC's study, estimated that 8 there was a maximum potential of 750 megawatts of small 9 cogeneration projects, of which they expected that the 10 successful ones would amount to only about 300 11 megawatts. AGRA's numbers are close but they are lower 12 than ours. And on Friday, Bruce Ander, of Toromont, 13 testified that their internal forecast was in the order 14 of 400 megawatts. 15 So the cumulative capacity of SEG projects by 16 three different groups are expected to be only 20 to 40 17 per cent of the projected load growth of 1401 megawatts 18 between Years 2000 and 2008. 19 So, permitting SEG projects to service load 20 growth would not likely reduce the historic load 21 available to service the historic transmission costs. 22 The load capacity of SEG projects will 23 minimize impact on the aggregate transmission rates. 24 There is a need for net load billing to enable 25 the SEG projects to happen. 26 EnergyLink has developed a number of SEG 27 projects in Ontario which are certain not to proceed. 28 If a partial or a whole gross load billing charge was Les Services StenoTran Services Inc. 613-521-0703 2671 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 levied on the project, these charges would eliminate the 2 location advantage of the SEG project which it is 3 entitled to and needs to offset its higher unit capital 4 cost relative to larger generators. 5 SEG projects already have to absorb the CTC 6 charge. 7 Net load billing for SEG projects would not be 8 a subsidy or an unwarranted exemption; it would just 9 preserve the location advantage of SEG projects, as is 10 done in normal business practice. 11 Decision on future transmission investments 12 for capacity expansion should pit transmission 13 investments costs against SEG costs without any 14 transmission charges. 15 Net load billing for SEG provides the proper 16 market signal for future transmission investment 17 decisions. 18 Net load billing will also provide fair 19 treatment, with respect to past SEG projects, and 20 equitable treatment, with respect to demand side 21 management or other methods of load reduction. 22 I would like to move on to the impact of SEG 23 projects on rates and cost shifting. 24 The impact of embedded generation on 25 transmission rates should not only evaluate the effects 26 of mood change in the denominator, as OHNC has done, but 27 it should also evaluate the revenue requirement effects 28 on the numerator. Les Services StenoTran Services Inc. 613-521-0703 2672 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 In response to our interrogatory for future 2 capital and expense transmission costs for capacity 3 expansion, OHNC indicated that such information was not 4 available. 5 The impact analysis is extremely sensitive to 6 revenue reductions due to embedded generation. As an 7 example, if the revenue requirement was to decline at 8 the same rate as load -- which is only .8 per cent per 9 year -- as a result of embedded generation, the 10 aggregate rates would remain the same as for the 100 per 11 cent gross load billing case with no embedded 12 generation. 13 There has been quite a number of questions, in 14 this regard, to EnergyLink's methodology of estimating 15 transmission capacity expansion costs, and I would like 16 to elaborate on how the savings were substantiated. 17 EnergyLink based avoidable transmission costs 18 on OHNC's Year 2000 capital program, which included 19 $29.5 million per year for capacity expansion, as shown 20 in Exhibit E, Tab 15, Schedule 3. 21 OM&A cost savings were not available and no 22 estimates were included in our analysis. 23 Several other sources were compared to this 24 29.5 million per year figure. One of them was shown in 25 Exhibit 15.2, which shows that the construction work in 26 progress, under the Uniform System of Accounts No. 2055, 27 to December 31, 2000, was $75.4 million of capital asset 28 work in progress. Les Services StenoTran Services Inc. 613-521-0703 2673 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 If we assume that this transmission 2 expansion-related work in progress occurred between two 3 to three years, the annual capital amount would be 4 $25-38 million per year. 5 This would suggest that there are transmission 6 expansion work going on in small lumps. for at least 7 several years. 8 This range would be consistent with our $29.5 9 million per year number. 10 Also, earlier on in OHNC's work, in their 11 Exhibit C5.1, they showed that the undepreciated fixed 12 assets and service was $8.357 billion. 13 On an unescalated basis, the average long-term 14 transmission capacity costs is $432 per kilowatt, 15 assuming an aggregate transmission capacity of 19,346 16 megawatts, in the Year 2000. This is a conservatively 17 low number since each past year's expenditures would 18 have to be escalated to the current day to estimate 19 current replacement costs. 20 For the assessment period, the average annual 21 escalation in demand is 175 megawatts. That's the 1,401 22 divided by eight increments. And average annual 23 transmission capital investment required would be $75.6 24 million per year. Much of this amount may be argued as 25 a sinking fund amount for large lumpy investments some 26 time in the future. 27 Our $29.5 million per year assumption is well 28 below this conservative long term average transmission Les Services StenoTran Services Inc. 613-521-0703 2674 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 capacity cost. I think the most relevant comparison we 2 have is with Undertaking F9.1, which shows the 3 incremental system values in 1992, and also in HR-24, 4 Interrogatory No. 2.15.10 shows the same numbers but 5 updated for 1995 incremental system values. 6 Incremental system values are avoided 7 annualized capital and OM&A costs associated with the 8 transmission system. It is interesting to note that the 9 1995 values were after the lumpy network transmission 10 capacity expansions completed for the GTA and eastern 11 Ontario regions that Dr. Warren has referred to. 12 The 1995 bulk transmission figures were lower 13 than the 1992 numbers. It went from roughly $13 to 14 $13.8 per kilowatt per year down to $5 in 1995. And 15 that's consistent with the expenditures that were made 16 in that period of time in those two regions. 17 Regional transmission numbers were adjusted 18 upwards from the range of $14.80 to $18 in 1995. If we 19 use the bulk and regional transmission avoided cost 20 numbers only, which were $5 and $18 per kilowatt per 21 year in 1995, the avoided annual transmission costs 22 would be $32.2 million in 1995 dollars. 23 If we escalate that with the CTI at 1.5 per 24 cent per year, we get to a final number of $34.7 million 25 per year in the year 2008. These are in year 2000 26 dollars. These numbers correspond reasonably well with 27 the $33.9 million per year, the same year 2000 dollars, 28 and in the year 2008 calculated in our evaluation, Les Services StenoTran Services Inc. 613-521-0703 2675 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 assuming that the capital avoided was $29.5 million per 2 year. 3 As supported by the above, the capital costs 4 for expansion in the year 2000, that's that $29.5 5 million per year number, was assumed to be the same each 6 year from the year 2001 to 2008. These capital costs 7 could be avoided if small embedded generation projects 8 were permitted with that load billing. 9 With reference to Exhibit E, Tab 15, Schedule 10 3, during earlier testimony by OHNC, Mr. Stephenson of 11 the PWU put it to Mr. Curtis of OHNC that the amount of 12 expenditures both in the year 2000 and beyond on 13 interconnect would be unaffected by any gross load or 14 net load determination. 15 Mr. Curtis replied yes. In terms of that 16 exhibit, there was a significant cost with interconnects 17 in that particular -- in the year 2000 for expansion. 18 All future expenditures for interconnect, as I read it, 19 is justified on the basis that large capacity on 20 interconnects with neighbouring IMOs will benefit 21 Ontario consumers by providing more competition in 22 supply and increased reliability of supply for Ontario. 23 Both these functions, in my view, could be met 24 with additional embedded generation. The interconnect 25 expansion costs ought to be included when considering 26 the choice between transmission expansion or embedded 27 generation. 28 The bulk of the interconnection expansion Les Services StenoTran Services Inc. 613-521-0703 2676 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 capital was allocated to the transformation connection 2 pool rather than network, which I found to be peculiar. 3 Expansion of any step-down transformation capacity of 4 less than 50 kilowatts could be avoided given advance 5 warning with embedded generation. 6 Our position on transmission expansion capital 7 requirement based on these four sources would still be 8 the $29.5 million per year figure. We feel that this is 9 reasonable for the purposes of our analysis. 10 In our evidence, embedded generation capacity 11 addition that's equal to load growth would cause the 12 expansion capital cost of $29.5 million to be deducted 13 each year from the annual capital program. By 2008, 14 annual revenue requirements is reduced by $33.9 million 15 per year, to a total of $1.129 billion per year of 16 revenue requirement for OHNC, all else being equal and 17 without reduction of OM&A costs. 18 This annual revenue requirement saving amounts 19 to $24.20 per kilowatt per year, or $2.02 per kilowatt 20 per month, which indicates that the revenue savings to 21 the transmission system is about 40 per cent of OHNC's 22 full rate of $4.94 per kilowatt per month, which would 23 be the amount lost due to load decline. 24 In our impact assessment, we completed three 25 cases. The evaluations follow OHNC's methodology to 26 calculate the impact on rates and cost shifting of small 27 embedded generation. The split of said projects amongst 28 the four customer groups was assumed to be equal at 25 Les Services StenoTran Services Inc. 613-521-0703 2677 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 per cent within each of the customer groups. 2 Three scenarios were evaluated, first with the 3 historic cap on load for gross load billing purposes, 4 that's shown in our Table 5, and SEG capacity at the 5 load growth of 1,401 megawatts. The avoided capital 6 cost in this case was $29.5 million per year with SEG. 7 In our second scenario, we put no cap on the 8 load so the load would follow the forecast provided by 9 OHNC. SEG capacity was at 545 megawatts, which was our 10 middle forecast, and the avoided capital cost was $11.5 11 million per year with SEG. This is just prorated down 12 of the $29.5 million for 545 megawatts as opposed to 13 1,401. 14 The last case, the third case, no cap on load 15 again in SEG at load growth of 1,401 megawatts with 16 avoided capital costs of $29.5 million. 17 In scenario one, with gross load billing 18 restricted to historic load cap, new load growth could 19 be handled by new SEG projects. Net load billing for 20 network and connection for SEG projects was assumed. 21 This case was based on the notion that existing loads 22 caused the construction of the existing transmission 23 system and new generating capacity up to the load growth 24 should be entitled to net load billing. 25 Historic load capping was suggested by OHNC 26 during the technical conference. The concept for 27 network charges only, according to OHNC, was to cap the 28 load at a delivery point at the historic level which Les Services StenoTran Services Inc. 613-521-0703 2678 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 OHNC proposed to be the load over the previous 12 2 months. 3 Charges at that delivery point will be based 4 on the higher of the historic load or the actual net 5 demand. OHNC intended in this process to allow net load 6 billing for embedded generation which would service new 7 loads. 8 The historic load cap sets a floor on loads 9 from which transmission costs are recovered. In this 10 scenario, the aggregate transmission rate is calculated 11 to be $4.86 per kilowatt per month, as long as SEG 12 capacity did not exceed load growth. The cost shifting 13 in this case was positive 2.9 per cent for the largest 14 ten MEU group and positive 3.1 per cent for other MEUs. 15 While there may be a change in distribution of 16 transmission costs, transmission rates remain the same 17 for all customer groups. This is shown in OHNC's 18 calculations where each scenario for cogeneration uses 19 the same aggregate transmission rate for each customer 20 group. 21 Each customer group's transmission rate for 22 network load connection and transformation connection 23 services is the same. Each pool's rate is only a 24 function of each pool's dollar amount divided by the 25 pool's total charge determinant. 26 The postage stamp policy is strictly adhered 27 to in these embedded generation scenarios with 28 transmission rates to all transmission customers the Les Services StenoTran Services Inc. 613-521-0703 2679 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 same. 2 When 100 per cent of the cogeneration capacity 3 is allocated by OHNC to direct customers, it appears 4 that the MEUs will incur cost allocation increases. 5 With only SEG projects, EnergyLink would allocate 6 generation capacity equally between all customer groups, 7 reducing cost shifting. 8 Since SEG projects can be located within LDCs 9 for hospital, universities and other institutions, SEG 10 projects have a more favourable distribution for LDCs 11 than OHNC's estimate for all cogeneration projects. 12 In our Scenario 2, Table 5B, we illustrate 13 that the effect of 545 megawatts a SEG projects relative 14 to the same OHNC base case of 100 per cent gross load 15 billing. This provides a clear comparison of net load 16 billing for connection and network charges for SEG 17 projects relative to the other options evaluated by 18 OHNC. 19 The aggregate transmission rate in this 20 scenario with 545 megawatts an SEG declined to $4.73 per 21 kilowatt per month by the year 2008. This is only 22 1.2 per cent above OHNC's 100 per cent gross load 23 billing base case, which has no embedded generation. 24 The transmission cost of all customer groups 25 declined in this scenario. The LDCs declined between 26 .09 to .15 per cent, pretty small; and the direct 27 customers declined between 6 to 9 per cent. All 28 customer groups benefitted in this analysis. Les Services StenoTran Services Inc. 613-521-0703 2680 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 If transmission rates remained constant for 2 all customer classes there would be no rate shifting. 3 In our Scenario 3, which is Table 5C, it 4 illustrates the effect of 1,401 megawatts a load growth 5 for SEG -- or an SEG project capacity equal to a load 6 growth of 1,401 megawatts relative to the same OHNC base 7 case of 100 per cent growth load billing. 8 Net load billing was assumed for connection 9 and network for the SEG projects. The aggregate 10 transmission rate declined to $4.86 per kilowatt per 11 month by the year 2008. This is 4 per cent above the 12 OHNC base case with no embedded generation. 13 The transmission costs for the MEUs remain 14 essentially unchanged. There was a decline of .09 per 15 cent for the largest 10 MEUs and a slight increase of 16 .08 per cent for the other MEU group, while the direct 17 customers declined between 16 and 25 per cent. 18 Again, transmission rates remain the same for 19 all customer classes. 20 There are a few supporting views from OPGI and 21 OHNC. 22 OPGI in their direct evidence of Dr. Orans did 23 acknowledge that new loads serviced by embedded 24 generation will not cause investment in network service 25 facilities. 26 OPGI also confirmed that a new load that is 27 installed contemporaneously with new embedded generation 28 should be billed on a net load billing basis for network Les Services StenoTran Services Inc. 613-521-0703 2681 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 services. 2 OHNC is also agreeable to having a cap to 3 historic loads apply only to network charges. New loads 4 would be on a net load billing basis. 5 EnergyLink would go further than that to say 6 that in this situation where load growth is serviced by 7 SEG projects and historic network line connection and 8 transformation connection investments are caused by 9 historic load levels and not caused by these new load, 10 net load billing should apply for SEG projects in this 11 instance. 12 Many SEG projects are expected within MEUs and 13 high growth areas where there is substantial diversity 14 of demand for capacity and connection facilities and 15 where relinquished capacity is easily reused by other 16 end users. 17 OHNC's continued expenditure on transmission 18 connection capacity expansion indicates the continued 19 need to expand to accommodate load growth. SEG projects 20 should therefore receive net load billing for connection 21 charges. 22 To wrap up, small embedded generators amount 23 to less capacity addition than other embedded generation 24 groups and have a minimal effect on aggregate 25 transmission rates and cost shifting. 26 A minimum bill may be based on a historic cap 27 on load for network and connection charges. SEG 28 projects need net load billing for network and Les Services StenoTran Services Inc. 613-521-0703 2682 ENERGYLINK PANEL 1, ev-in-ch (Wong) 1 connection charges to proceed and SEG projects achieve 2 the high energy efficiency. 3 That concludes my testimony. 4 THE PRESIDING MEMBER: Thank you, Mr. Wong. 5 Who is going to lead off? 6 Mr. Fisher. 7 MR. FISHER: Good morning, Dr. Higgin. 8 We have no questions. 9 THE PRESIDING MEMBER: Thank you. 10 Mr. Budd. 11 MR. BUDD: No, thank you, sir. 12 THE PRESIDING MEMBER: Okay. 13 Mr. Adams, please. Thank you. 14 MR. ADAMS: Just a couple of questions. 15 CROSS-EXAMINATION 16 MR. ADAMS: Good morning, Mr. Wong. 17 MR. WONG: Good morning. 18 MR. ADAMS: Just a couple of questions of 19 clarification. 20 First of all, except for new connection, or 21 charges related to new connection, under OHNC's proposal 22 generators won't pay for T-service directly. 23 We agree on that? 24 MR. WONG: Would you repeat that, Tom? 25 MR. ADAMS: Except for new connection, charges 26 for new connection, under OHNC's proposal, and under 27 gross or net scenarios, generators won't pay for 28 T-service? Les Services StenoTran Services Inc. 613-521-0703 2683 ENERGYLINK PANEL 1, cr-ex (Adams) 1 MR. WONG: That's correct, I believe. 2 MR. ADAMS: So when we review your statement 3 with regard to charges to SEG projects and levelling of 4 the playing field, and whatnot, can we read that as 5 charges to consumers of power generated by SEG projects? 6 MR. WONG: Yes. 7 MR. ADAMS: Okay. 8 Let me understand your proposal for net load 9 billing and its implications. 10 If your proposal for net load billing for 11 users of SEG-generated power is accepted, who will get 12 the benefit of the difference between net and gross load 13 billing? 14 MR. WONG: Well, the benefits would be shared 15 between the investors of the SEG projects, which may be 16 the end use customers themselves, and the end use 17 customers in the case where there are separate 18 ownerships. 19 MR. ADAMS: Do you have any rule of thumb of 20 what you would expect to see in terms of the split in 21 those benefits? Who would get what portion? 22 MR. WONG: Well, Tom, I don't think that these 23 savings in transmission costs have a logistical way of 24 allocating to either the user or the project. It's more 25 it is all encompassed in the economics of the project 26 and the viability of it for both the customer and then 27 for the owner of the SEG project. 28 MR. ADAMS: Yes. I understand. Les Services StenoTran Services Inc. 613-521-0703 2684 ENERGYLINK PANEL 1, cr-ex (Adams) 1 I wonder if you can help me understand: As a 2 rule of thumb -- you know, I don't want to get into the 3 details of your business proposal, but if you could give 4 me just a kind of illustrative understanding of, with 5 current gas costs, what portion of the delivered cost of 6 power from SEG projects would be represented by fuel 7 costs? 8 MR. WONG: Anywhere from 60 to 75 per cent as 9 a rough guess. 10 MR. ADAMS: Gas prices right now are at a 11 relatively high level, which is good for gas producers 12 but for consumers has some impact. 13 If gas prices -- how much would gas prices 14 have to fall to bring the delivered cost of SEG power 15 under a gross load billing scenario down to where you 16 would like to see them under net load billing? 17 MR. ADAMS: That's a good question, but I 18 don't think it is that relevant. The reason for that 19 is, if natural gas is on the margin for -- as is 20 expected in the future from merchant generators, so SEG 21 projects always have to basically compete with the 22 electricity that is supplied by merchant generators 23 through the transmission distribution system to the end 24 user. 25 So if natural gas prices were high or low, it 26 would affect -- in relative sense, relative to the 27 capacity side -- the same for SEG generators as for 28 merchant. So you still need that advantage -- location Les Services StenoTran Services Inc. 613-521-0703 2685 ENERGYLINK PANEL 1, cr-ex (Adams) 1 advantage as I refer to it -- for the SEG projects, and 2 you need net load billing probably for a very wide range 3 of natural gas prices. 4 MR. ADAMS: let me look at the benefit of 5 local production in general terms with you and expand my 6 understanding in that area. 7 Would you agree with me that local production 8 has -- I just want to focus on the T-service benefits. 9 There may be many benefits that extend beyond T-service, 10 but I want to focus for a minute just on T-service 11 benefits. 12 Would you agree with me that local production 13 can reduce line losses? 14 MR. WONG: Yes, they certainly can. 15 MR. ADAMS: How does that work? In general 16 terms, can you help explain that? 17 MR. WONG: Well, there is a -- the 18 transmission system itself has line losses of about 4 19 per cent, and the distribution system has line losses 20 between 3 and -- sorry, between 2 and 4 per cent. So if 21 you can locate a SEG project at the end of the line, in 22 effect, you don't have to pay for the line loss in 23 electricity from a merchant generator to the order of 7 24 to 9 per cent. 25 MR. ADAMS: Okay. 26 How about potential security benefits that 27 might arise from local generation. Would you agree with 28 me that there are potential security benefits that might Les Services StenoTran Services Inc. 613-521-0703 2686 ENERGYLINK PANEL 1, cr-ex (Adams) 1 arise? 2 MR. WONG: Certainly. 3 MR. ADAMS: Can you describe how those would 4 work? 5 MR. WONG: It would certainly improve 6 reliability for supply of power to the end connected 7 consumer and even for people that are connected on the 8 distribution system when there is a failure of any sort 9 on the transmission system. We had an example of that a 10 couple of winters ago. 11 MR. ADAMS: How about relieving pressure on 12 the need for expansion. You spoke about this 13 extensively in your evidence-in-chief. Would you agree 14 with me that local generation only relieves pressure for 15 expansion of transformer and transmission service if the 16 reliability of the local generation is to an adequate 17 standard? Is that correct? 18 MR. WONG: No. I would think that you would 19 have potential for relieving constraints, not only in 20 the connection facilities but also on the network as 21 well to the extent that there is capacity on the network 22 to avoid. 23 THE COURT REPORTER: I'm sorry, sir, could you 24 repeat that? 25 MR. WONG: I'm sorry, I should rephrase -- to 26 the extent that there are constraints on the network 27 system to avoid. 28 MR. ADAMS: Constraints in terms of congestion Les Services StenoTran Services Inc. 613-521-0703 2687 ENERGYLINK PANEL 1, cr-ex (Adams) 1 or -- 2 MR. WONG: Capacity constraints, yes. 3 MR. ADAMS: Okay. 4 Are you familiar with locational marginal 5 pricing for energy? 6 MR. WONG: Somewhat. 7 MR. ADAMS: In general terms, do you support 8 this direction? The Market Design Committee recommended 9 that sometime soon after market opening Ontario ought to 10 implement some system of locational marginal pricing for 11 energy. Do you support that recommendation? 12 MR. WONG: Yes, I do. 13 MR. ADAMS: Would that benefit -- let me see 14 if I can put words in your mouth and see if you will 15 agree with me, just to make this short. 16 Would you agree with me that local marginal 17 pricing for energy would achieve many of the benefits 18 that we have just talked about here in terms of the 19 contribution that local generation can provide to the 20 power system for relieving transmission costs? 21 MR. WONG: I agree with that. 22 MR. ADAMS: Okay. But we don't have 23 locational marginal pricing. 24 Is your proposal for net load billing for SEG 25 projects an alternative to locational marginal pricing? 26 MR. WONG: Like you say, we don't have 27 locational marginal pricing at this point in time. What 28 is on the table is gross or net load billing. I think, Les Services StenoTran Services Inc. 613-521-0703 2688 ENERGYLINK PANEL 1, cr-ex (Adams) 1 given our evidence, that SEG project capacity doesn't 2 exceed load growth and that there are some transmission 3 constraint costs that -- transmission expansion costs 4 that could be avoided. I think it is pretty clear that 5 there are some significant benefits for each of the 6 customer groups by allowing projects like this. 7 THE PRESIDING MEMBER: Speak up, Mr. Wong. 8 I'm sorry. 9 THE REPORTER: With your face turned that way 10 it is almost impossible to hear what you are saying, 11 sir. 12 THE PRESIDING MEMBER: Could you try to put 13 the microphone closer. 14 --- Pause 15 MR. ADAMS: You are too soft spoken, Mr. Wong. 16 MR. WONG: I have lost my train of thought, 17 but let me try again. 18 We don't have locational marginal pricing at 19 this point in time. What is on the table is net load 20 billing versus gross load billing. We have tried to 21 demonstrate that for SEG project capacity, which is 20 22 to 40 per cent of the load growth, it has a very low 23 impact on aggregate rates. Also, from the standpoint 24 that I think we have shown by a number of sources, there 25 are some transmission expansion cost savings other than 26 the large lumpy investments that Dr. Orans referred to 27 -- and these smaller lumps occur quite regularly and 28 they have been incurred in the last few years -- we Les Services StenoTran Services Inc. 613-521-0703 2689 ENERGYLINK PANEL 1, cr-ex (Adams) 1 think that from a general concept standpoint these sort 2 of costs could be avoided if you could put in generation 3 to relieve the congestion that causes that expenditure. 4 MR. ADAMS: Let's take a scenario where your 5 proposals are accepted. Would it be fair to say that 6 your company's interest in achieving locational marginal 7 pricing -- if net load billing is in place for SEG 8 projects, your company's interest in Ontario achieving 9 locational marginal pricing for energy will be 10 relatively less than were it the case that gross load 11 billing prevailed? 12 MR. WONG: I wouldn't say less, but we 13 certainly would be able to conduct our business and 14 continue on. I think we would be interested to 15 participate in how locational marginal pricing might 16 occur and under what rules. 17 MR. ADAMS: Understood. Let's take the 18 scenario where, say, the Board is so moved not to accept 19 net load billing for SEG projects and continues with the 20 Market Design Committee's recommendations for gross load 21 billing in one form or another, if that were the case, 22 would you want to see the Board apply its moral suasion 23 to encouraging the pursuit of locational marginal 24 pricing for energy? 25 MR. WONG: Certainly. 26 MR. ADAMS: That's great. Thank you very 27 much. 28 THE PRESIDING MEMBER: Thank you, Mr. Adams. Les Services StenoTran Services Inc. 613-521-0703 2690 ENERGYLINK PANEL 1, cr-ex (Adams) 1 Anyone else? 2 Mr. Campbell. 3 CROSS-EXAMINATION 4 MR. CAMPBELL: Good morning, Mr. Wong. 5 I would like to take you first, please, to 6 your testimony, Exhibit H-15-1 at page 4, please. 7 --- Pause 8 MR. WONG: Yes. 9 MR. CAMPBELL: There, at the paragraph that is 10 numbered 6(2), you say: 11 "Small Embedded Generation projects are 12 generally located behind an LDC, in high 13 growth areas, and will act to relieve 14 congestion and reduce or defer the need 15 for transmission system expansion or 16 reinforcement." 17 Do you see that? 18 MR. WONG: Yes, I do. 19 MR. CAMPBELL: Before turning to what OHNC's 20 views are in that matter, which is the balance of the 21 paragraph, I would like to ask you whether you believe 22 that is a true statement that applies to all embedded 23 generation? 24 MR. WONG: No, I don't believe that is true 25 for all embedded generation. 26 MR. CAMPBELL: Would it apply to most of it? 27 Give me a sense of, in your opinion, what the proportion 28 would be of embedded generation to which that statement Les Services StenoTran Services Inc. 613-521-0703 2691 ENERGYLINK PANEL 1, cr-ex (Campbell) 1 would apply. 2 MR. WONG: Did you want to cut the line along 3 capacity or number of projects? 4 MR. CAMPBELL: I think just proportion of 5 projects. 6 MR. WONG: I think a much smaller proportion 7 would be located behind LDCs with SEG projects, and my 8 belief is that a much larger capacity would be developed 9 outside of LDCs. 10 MR. CAMPBELL: So that you would agree that 11 only a small portion would act to relieve congestions or 12 reduce or defer the need for transmission system 13 expansion or reinforcement. Is that what I'm hearing 14 you say now? 15 MR. WONG: No; I am saying that SEG projects 16 are located, by and large, to a large proportion, behind 17 LDCs. 18 Your question was in regards to all embedded 19 generation, I believe. But I think the statement still 20 holds. I think I gave you examples of some 10 projects 21 that are existing today which all are -- except for 22 one -- behind an LDC of one sort or another. 23 MR. CAMPBELL: In speaking to projects, 24 generally, are you relying on the quote from OHNC that 25 you have included in your testimony to reach that 26 conclusion? 27 MR. WONG: To some extent, I believe that is 28 correct, yes. Les Services StenoTran Services Inc. 613-521-0703 2692 ENERGYLINK PANEL 1, cr-ex (Campbell) 1 MR. CAMPBELL: Do you have any other kind of 2 information around this that you are relying on in 3 making this statement about relieving congestion and so 4 on? 5 MR. WONG: Maybe I don't follow you. 6 This statement is in regards to small embedded 7 generation projects, only. 8 MR. CAMPBELL: Yes, I understand that. 9 What I am asking you is, in putting the 10 proposition forward that those SEG projects would 11 relieve congestion or obviate the need for transmission 12 reinforcement, what I am asking you is whether -- first, 13 how often that would happen and, secondly, how you 14 arrived at that opinion. 15 MR. WONG: Well, there are expenditures being 16 made by OHNC for expansion on connection facilities, as 17 well as network, and if expenditures are being made for 18 expansion there, then, certainly, I would think there 19 are opportunities to provide SEG projects to meet the 20 expanded load in which those expenditures were intended 21 to service and avoid those costs. 22 MR. CAMPBELL: But in making that statement 23 about SEG generation, generally, have you canvassed the 24 Ontario situation to determine whether that circumstance 25 applies in most cases, that, in fact, they would relieve 26 congestion or that they would have the other benefits 27 that you are talking about -- avoiding transmission 28 expenditures, for instance? Les Services StenoTran Services Inc. 613-521-0703 2693 ENERGYLINK PANEL 1, cr-ex (Campbell) 1 I want to know whether that is something that 2 you have looked at separately or you are relying on what 3 OHNC has said about that. 4 MR. WONG: No; I think, to a large part, I am 5 relying on the evidence that has been presented here, by 6 OHNC and others. 7 MR. CAMPBELL: In making that statement, I 8 take it you are relying on the portion of the evidence 9 that is cited in your paragraph 6(2), on page 4. Is 10 that correct? 11 MR. WONG: That is correct. 12 MR. CAMPBELL: All right. I would like to 13 take you to that, if I could, please. It is at 14 Exhibit B, Tab 4, Schedule 2, page 48. I think your 15 reference here is to "Schedule 1", but I think when you 16 look at the excerpt, it is actually "Schedule 2". Is 17 that the -- I think that is the paragraph that you have 18 been looking at. 19 --- Pause 20 MR. LYLE: Could you repeat the reference, 21 Mr. Campbell. 22 MR. CAMPBELL: Yes. It is Exhibit B, Tab 4, 23 Schedule 2, page 48. 24 MR. LYLE: Thank you. 25 MR. CAMPBELL: I think in Mr. Wong's 26 testimony, it is referred to as "Schedule 1", but I 27 think you will find the correct reference is 28 "Schedule 2". Les Services StenoTran Services Inc. 613-521-0703 2694 ENERGYLINK PANEL 1, cr-ex (Campbell) 1 MR. WONG: I believe you are correct. 2 MR. CAMPBELL: All right. I think Schedule 1 3 only has six pages, so it sort of led us to find 4 page 48. 5 Now, could you read, please, the last full 6 sentence of the paragraph that you have referenced. I 7 think it starts with the "Indeed" in the last bullet 8 point on page 48. 9 Would you read that into the record, please. 10 MR. WONG: 11 "In these cases, the load supplied by the 12 generator is not, strictly speaking, 13 bypassing transmission-sunk costs." 14 Sorry. It continues on: 15 "Indeed, there should be a provision that 16 such load not be treated as bypassing 17 sunk costs although such situations arise 18 so infrequently in view of the bulk 19 nature of the transmission investment 20 that they should be treated as exceptions 21 rather than as rules." (As read) 22 MR. CAMPBELL: I take it that having relied on 23 OHNC, you would agree that the Board, in dealing with 24 this point in your testimony, should treat this as a 25 very infrequent situation? 26 MR. WONG: No, I don't believe so. I think 27 the fact that there are moneys spent on a regular basis 28 for transmission capacity expansion ought to be the Les Services StenoTran Services Inc. 613-521-0703 2695 ENERGYLINK PANEL 1, cr-ex (Campbell) 1 point that should be considered. 2 MR. CAMPBELL: But, Mr. Wong, you told me 3 before that you relied on this statement from OHNC in 4 dealing with your view as to how often that happened. 5 Do you have any evidence that contradicts 6 OHNC's view that those situations arise so infrequently 7 that they should be treated as exceptions rather than 8 rules? 9 MR. WONG: Well, in reviewing all of the 10 information that is out there, I think the costs 11 expended for transmission expansion is one. I think, 12 certainly, the incremental system costs, or values, that 13 are put on the transmission system is another reference 14 point that, in fact, there are transmission costs that 15 could be avoided. 16 MR. CAMPBELL: All right. Would you agree 17 with me, at least this far, to the extent that you are 18 relying on OHNC's view, OHNC's view is that this is so 19 infrequent that it should be treated as an exception 20 rather than a rule? 21 MR. WONG: I accept that as OHNC's position, 22 yes. 23 MR. CAMPBELL: Now, in talking about these 24 other investments, you talked a little bit, this 25 morning, about the interconnection investment, for 26 instance, that is referred to at E15.3. 27 Would you agree with me that if that 28 interconnection cost was going to take place anyway, Les Services StenoTran Services Inc. 613-521-0703 2696 ENERGYLINK PANEL 1, cr-ex (Campbell) 1 regardless of whatever level of investment took place in 2 small embedded generation, then that interconnection 3 cost shouldn't be taken into account as a cost avoided 4 by small embedded generation? 5 MR. WONG: If it was to be expended anyways 6 and can't be -- and the objectives behind that 7 expenditure can't be serviced by small embedded 8 generators, I would agree with you. 9 MR. CAMPBELL: All right. Now, on page 3 of 10 your testimony, you make the statement that -- and it is 11 right under the heading "5." -- you make the statement: 12 "Due to their smaller size, Small 13 Embedded Generation projects have higher 14 unit capital costs than large merchant or 15 wholesale power plants. 16 Do you see that? 17 MR. WONG: Yes, I do. 18 MR. CAMPBELL: Now, you go on to say that your 19 projects would be uneconomic at gross load billing, or 20 even 50 per cent of gross load billing, where network is 21 applied to them. 22 I guess my question to you is: What level of 23 subsidy, or support, do your projects need to be 24 economic? Would net for network and gross for 25 connection be enough? Or do you need net for network 26 and net for connection? 27 MR. WONG: We need net for network and net for 28 connection. Les Services StenoTran Services Inc. 613-521-0703 2697 ENERGYLINK PANEL 1, cr-ex (Campbell) 1 MR. CAMPBELL: All right. If the situation is 2 that -- I guess under OHNC's proposal -- that if 3 embedded generation is installed at the same time that a 4 customer's load grows, that customer will get net load 5 billing for a new embedded generation. Correct? That 6 is OHNC's proposal. 7 MR. WONG: For network services, yes. 8 MR. CAMPBELL: When you referred to Dr. Orans' 9 view, this morning, I take it that was the reference in 10 your testimony, that Dr. Orans agreed with the view that 11 new load installing matched amounts of new embedded 12 generation would be billed net. 13 You understood that, I take it, from his 14 testimony? 15 MR. WONG: Yes, I do. 16 MR. CAMPBELL: That was what you were 17 referring to this morning in referring to -- 18 MR. WONG: I believe that's correct, yes. 19 MR. CAMPBELL: Then on pages 5 and 6 of your 20 testimony, you talked about capping load at historic 21 levels. I want to be sure that I understand what you 22 are saying. I understand your proposal is to load 23 generally and you are not talking about the situation 24 where a specific customer's load grows and that specific 25 customer installs embedded generation. Do I have that 26 right? 27 MR. WONG: That's correct. 28 MR. CAMPBELL: So you are talking generally Les Services StenoTran Services Inc. 613-521-0703 2698 ENERGYLINK PANEL 1, cr-ex (Campbell) 1 about the situation where load grows across the system 2 and at the same time some customers install embedded 3 generation. 4 MR. WONG: That's correct. 5 MR. CAMPBELL: Now, if you assume with me that 6 the Ontario transmission system generally has spare 7 network capacity, wouldn't it be true that system load 8 growth generally would benefit all customers. It would 9 reduce their unit cost of transmission charges, their 10 unit price for transmission charges. Correct? 11 MR. WONG: Yes, it would. 12 MR. CAMPBELL: And your proposal, the cap load 13 at historic levels, and allowed any load growth then to 14 offset the impacts of embedded generation, what that 15 does is essentially capture the benefit of all of this 16 load growth for the embedded generators. Isn't that 17 fair? 18 MR. WONG: That's fair. 19 MR. CAMPBELL: And, finally, at page 6 of your 20 evidence, as I understand it, guess at the end of the 21 second paragraph down starting "OHNC" -- if I understand 22 it, you are suggesting that a customer with an existing 23 connection facility that serves that customer and maybe 24 a few others should be able to avoid cost responsibility 25 for those connection facilities by installing embedded 26 generation. 27 I guess I would just like to understand why 28 you are suggesting they should be able to avoid Les Services StenoTran Services Inc. 613-521-0703 2699 ENERGYLINK PANEL 1, cr-ex (Campbell) 1 connection costs. 2 MR. WONG: I don't think the usage of those 3 connection facilities would be reduced as long as the 4 SEG projects behind those customers don't exceed the 5 rate loads. 6 MR. CAMPBELL: I'm not quite sure I understand 7 your answer. What I'm asking you is: They have 8 incurred or caused the connection cost to be incurred. 9 They now put in a generator. It's not clear to me why 10 with only a few customers on that line, even accepting 11 some of your other reasoning in other areas, they should 12 be able to abandon those costs. 13 MR. WONG: I don't think we are suggesting 14 that they abandon those costs. A customer such as an 15 LDC, for example, may have maybe one transmission 16 customer but there are numerous end users behind them. 17 MR. CAMPBELL: I'm putting to you the 18 situation where there is a connection line with one 19 customer who puts in a small embedded generator and 20 maybe only a few other customers on that connection 21 line. It was put in specifically to serve the very 22 small group of customers. 23 MR. WONG: It was put in and caused by the 24 historic load. What I am saying here is for new load 25 growth, that segment that is over and above historic 26 load really didn't cause the construction and the 27 expenditures relating to that connection facility and 28 ought not have to bear the cost of it then. Les Services StenoTran Services Inc. 613-521-0703 2700 ENERGYLINK PANEL 1, cr-ex (Campbell) 1 MR. CAMPBELL: You are only treating this for 2 new additional load over and above the load that was 3 taken previously on that connection facility. Is that 4 what I'm understanding this to mean? 5 MR. WONG: I think in general that's what I'm 6 referring to. Yes. 7 MR. CAMPBELL: So the previous load should 8 remain responsible for those connection costs, 9 regardless of putting in the generation, at least to the 10 level of those historic loads. Is that right? 11 MR. WONG: Yes. 12 MR. CAMPBELL: Okay. Thank you, Mr. Chairman. 13 Those are my questions. 14 THE PRESIDING MEMBER: Thank you, 15 Mr. Campbell. 16 Good morning, Ms. Friedman. 17 CROSS-EXAMINATION 18 MS FRIEDMAN: I can't see Mr. Wong from that 19 seat, so I am just going to move over. 20 --- Pause 21 MS FRIEDMAN: Mr. Wong -- 22 THE PRESIDING MEMBER: Could we just ask you 23 to try real hard because we are having trouble getting 24 you on this side of the room. I don't know why. 25 MS FRIEDMAN: I understand that the market 26 rules are implementing a mechanism to recognize the 27 benefits of local generation in terms of line loss 28 savings. Is that your understanding as well? Les Services StenoTran Services Inc. 613-521-0703 2701 ENERGYLINK PANEL 1, cr-ex (Friedman) 1 MR. WONG: I'm not aware of that. 2 MS FRIEDMAN: I have a question about Table 4 3 which is at page 13 of your prefiled evidence. 4 MR. WONG: Did you say page 13? 5 MS FRIEDMAN: Page 13. I contrast that table 6 just for your reference to OHNC's evidence, Exhibit D, 7 Tab 5, Schedule 2, page 4 of 7, which is OHNC's 8 assumptions for siting of new embedded generation. 9 I look at your Table 4, the line for 10 cogeneration, you have got 25 per cent in ten large 11 LDCs, 25 per cent within OH retail and other MEUs, 25 12 percent in the 20 large directs and then 25 per cent the 13 other directs. 14 I note that in OHNC's Table 3, Exhibit D, Tab 15 5, Schedule 2, page 4 of 7, OHNC assumes zero embedded 16 generation, cogeneration, within the LDCs. Can you 17 please explain to me why you have 25 per cent of the 18 generation being sited within large LDCs and 25 per cent 19 within other MEUs in light of OHNC's evidence? 20 MR. WONG: Certainly. As far as I can tell in 21 the reading of the Monenco AGRA report, there didn't 22 seem to be any evidence in there as to where all the 23 cogeneration projects would be located. For this 24 particular table that you are referring to from OHNC, 25 from memory, OHNC internally made that allocation of 75 26 per cent to the 20 large directs and 25 per cent to the 27 other directs. 28 Here in my Table 4, I'm referring to SEG Les Services StenoTran Services Inc. 613-521-0703 2702 ENERGYLINK PANEL 1, cr-ex (Friedman) 1 projects. I'm looking for the split of generation or 2 SEG generation amongst the four customer groups here. 3 Although most of the existing SEG projects are located 4 behind the first two columns, the large LDCs and the 5 other LDCs in the examples that I gave you, it is our 6 experience in working in the marketplace that there 7 really are projects in all four categories, so we took a 8 more conservative approach and divided the SEG project 9 capacity equally amongst all customer groups. 10 Rather than taking, say, a more aggressive 11 approach which could say for SEG projects that 90 per 12 cent of the projects should be behind LDCs and 10 per 13 cent behind the directs, which would have swung the cost 14 shifting issue much more in favour of the LDCs. 15 MS FRIEDMAN: Do you have in your prefiled 16 evidence that data that underlines those percentages? 17 MR. WONG: No. It's not in the prefiled 18 evidence. 19 MS FRIEDMAN: This is your internal corporate 20 information. 21 MR. WONG: Yes, it is. 22 MS FRIEDMAN: Thank you. Those are my 23 questions. 24 THE PRESIDING MEMBER: Thank you, Ms Friedman. 25 Next, Board staff, please. Mr. Lyle. 26 EXAMINATION 27 MR. LYLE: Thank you, Mr. Chair. 28 Mr. Wong, in your evidence you stated that Les Services StenoTran Services Inc. 613-521-0703 2703 ENERGYLINK PANEL 1, ex (Lyle) 1 EnergyLink and its partners are involved with several 2 small embedded cogeneration projects being developed in 3 Ontario. Can you tell me how many projects you are 4 involved with? 5 MR. WONG: We are involved with about 11 6 currently, at various stages of development. 7 MR. LYLE: And what would the total potential 8 generation capacity of all those projects together be? 9 MR. WONG: If they were all successful, they 10 would amount to something like 110 or 120 megawatts. 11 MR. LYLE: Now, is it your evidence that all 12 of those projects would be uneconomic under OHNC's 13 proposal or just some of them? 14 MR. WONG: All of them would be uneconomic. 15 MR. LYLE: If the Board was to expand the 16 proposed one megawatt exemption from gross load billing 17 in OHNC's proposal so that that exemption became an 18 exemption for any projects 20 megawatts and under, would 19 that address all of your concerns? 20 MR. WONG: Yes, it would. All of our projects 21 are between the five and 20 megawatt range. 22 MR. LYLE: I just want to finally turn you, 23 sir, to an answer to an interrogatory from OPGI which 24 you gave. It's at Exhibit E, Tab 45, Schedule 4. 25 --- Pause 26 MR. WONG: Which Interrogatory of OPGI? 27 MR. LYLE: Number four. 28 MR. WONG: Number four. Les Services StenoTran Services Inc. 613-521-0703 2704 ENERGYLINK PANEL 1, ex (Lyle) 1 MR. LYLE: OPGI Number four. 2 MR. WONG: I have that. 3 MR. LYLE: There is reference in there to 4 proposed transmission rates related to embedded 5 generation, proposing net load billing for all embedded 6 generation with the ratchet mechanism that was going 7 before the Alberta regulator. Has the Alberta regulator 8 now made its decision in that case? 9 MR. WONG: Yes, it has. 10 MR. LYLE: Has the proposal set out in your 11 response been approved by the Alberta regulator or has 12 it been changed? 13 MR. WONG: Yes, it has. 14 MR. LYLE: It has been approved? 15 MR. WONG: The ratchet mechanism as outlined 16 here, has been approved for both industrial as well as 17 residential/commercial customers. 18 MR. LYLE: Thank you. 19 Those are all my questions. 20 THE PRESIDING MEMBER: Thank you, Mr. Lyle. 21 Mr. Rogers. 22 MR. ROGERS: Yes, thank you. Just a few. 23 CROSS-EXAMINATION 24 MR. ROGERS: Mr. Wong, you told us that you 25 have been involved in developing some projects here in 26 Ontario. Can you tell us which projects you have 27 developed here? 28 MR. WONG: No, I'm sorry, I can't. Les Services StenoTran Services Inc. 613-521-0703 2705 ENERGYLINK PANEL 1, cr-ex (Rogers) 1 MR. ROGERS: Why can't you? Is it 2 confidential you mean or you don't remember? 3 MR. WONG: They are confidential with our 4 partners as well as to our competitors. We don't really 5 want them to know where we are working. 6 MR. ROGERS: Oh, I mean ones that are 7 completed. 8 Have you completed some projects? 9 MR. WONG: No. All these projects in Ontario 10 are awaiting decision from the OEB at this point. 11 MR. ROGERS: I thought you said that you had 12 developed some projects in Ontario, but I misunderstood 13 you, did I? 14 MR. WONG: I think you did. 15 MR. ROGERS: All right. 16 So what you presently have, then, are some 17 projects you are working on in Ontario. 18 MR. WONG: That's correct. 19 MR. ROGERS: They are all in the planning 20 stage. None are under construction? 21 MR. WONG: None are in construction, but 22 certainly some of them are far enough along that 23 construction could start very quickly if we had a 24 favourable ruling from the Board. 25 MR. ROGERS: You mean you have contracts 26 signed with people to go ahead if you get the net load 27 billing result here? 28 MR. WONG: Yes. Les Services StenoTran Services Inc. 613-521-0703 2706 ENERGYLINK PANEL 1, cr-ex (Rogers) 1 MR. ROGERS: You do? 2 MR. WONG: Yes. 3 MR. ROGERS: Are you able to tell us how many 4 contracts, how many megawatts do you actually have 5 contracted, under contract now, they will proceed if you 6 get a net load result out of this hearing? Is that 7 confidential? 8 MR. WONG: I would prefer to keep that 9 confidential, yes. 10 MR. ROGERS: You said a moment ago, and I was 11 surprised by this, that if my client's proposal for a 12 50 per cent access charge is accepted that not one of 13 those projects will proceed. Is that right? 14 MR. WONG: That's correct, because your 15 client's proposal essentially amounts to some 16 70 per cent gross load billing which is -- 17 MR. ROGERS: How do you get to 70 per cent 18 from 50 per cent? 19 MR. WONG: Well, it's 50 per cent on net but 20 it is 100 per cent gross on connections. 21 MR. ROGERS: On connections. 22 And you said that if the Board doesn't approve 23 net load billing for connections, then none of these 24 projects would go ahead either. Is that right? 25 MR. WONG: That's correct. 26 These projects are already weighted down by 27 the CTC and the higher costs per unit capacity that it 28 takes to construct these projects and it just simply Les Services StenoTran Services Inc. 613-521-0703 2707 ENERGYLINK PANEL 1, cr-ex (Rogers) 1 can't absorb any more costs. 2 MR. ROGERS: It sounds like they are right on 3 the margin, these projects. I mean, even if we went to 4 25 per cent modified net load billing, as my client 5 calls it, but rather than a 50 per cent charge or a 6 25 per cent charge, all of your projects would be 7 uneconomic. 8 MR. WONG: Twenty-five per cent gross load on 9 network and 100 per cent on connection, that's correct. 10 MR. ROGERS: Help me with the sensitivity 11 about the exemption levels now. My client proposes a 12 1 megawatt exemption. You are aware of that? 13 MR. WONG: Yes, I am. 14 MR. ROGERS: If the exemption were raised to, 15 let us say, 5 megawatts by this Board, what would that 16 do to your 11 projects? Would any proceed under that 17 basis? 18 MR. WONG: Yes. A few of them are in that 19 range so they could proceed on a net load billing basis. 20 MR. ROGERS: A few. Are you able to help me 21 as to what percentage of the 11 projects that you have 22 in terms of megawatts would proceed with a 25 per cent 23 net billing -- I'm sorry. 24 I'm sorry, I think you said a 5 megawatt 25 exemption level. 26 MR. WONG: I think one or two of the 11. 27 MR. ROGERS: How about megawatts? Are you 28 able to give me a percentage roughly? Are we talking Les Services StenoTran Services Inc. 613-521-0703 2708 ENERGYLINK PANEL 1, cr-ex (Rogers) 1 about 10 per cent or so of the megawatts? 2 MR. WONG: Roughly that, yes. 3 MR. ROGERS: Has your company actually 4 developed projects in Alberta? 5 MR. WONG: Our company operates -- we are a 6 development company that operates with an assortment of 7 partners that participate in these projects. As a 8 group, our partners have projects in Alberta and they 9 also have projects here in Ontario. 10 MR. ROGERS: Some of your partners have 11 projects here in Ontario? 12 MR. WONG: That's correct. 13 MR. ROGERS: I was just trying to find out 14 about Energylink though. Have you actually developed a 15 project in Alberta? 16 MR. WONG: No, we haven't. 17 MR. ROGERS: Thank you, Mr. Wong. 18 Those are my questions. 19 Thank you sir. 20 THE PRESIDING MEMBER: Thank you. 21 Mr. Vlahos. 22 MR. VLAHOS: Mr. Wong, I don't have any 23 questions, I am just curious though. 24 I noticed that your company is a member of 25 IPPSO, is that correct, or are you yourself a member of 26 IPPSO? How does it work? 27 MR. WONG: The company is a member of IPPSO. 28 MR. VLAHOS: The company. Les Services StenoTran Services Inc. 613-521-0703 2709 ENERGYLINK PANEL 1 1 Can you tell me why you would not be 2 empanelled panel with the IPPSO panel? 3 MR. WONG: I think the IPPSO panel has a -- or 4 the IPPSO position applies to a broader range of 5 embedded generation projects, some of which are 6 connected, as an example, on the distribution system and 7 some of which, many of which are connected to the 8 transmission system voltage level. From the onset we 9 wanted to make sure that the benefits of the arguments 10 that pertained to small embedded generators at the very 11 end of the supply chain, as I call it, could be heard 12 and the impact of that segment of projects could be 13 understood. 14 MR. VLAHOS: Did you have those discussions 15 with the team of IPPSO that was looking into making a 16 filing or intervention before the Board? 17 MR. WONG: I expressed that view to several of 18 the members in IPPSO. 19 MR. VLAHOS: Okay. 20 Thank you. 21 THE PRESIDING MEMBER: I would just like to 22 understand from you what your proposal is, just so I'm 23 very clear. 24 With respect to embedded generation -- we 25 understand the network now we are talking about behind 26 the meter -- is your proposal that the gross portion of 27 the customer's load is met by the transmission 28 expansion? The transmission -- start again. Les Services StenoTran Services Inc. 613-521-0703 2710 ENERGYLINK PANEL 1 1 The growth portion of the load of the 2 customer, does that then offset the cogeneration or the 3 embedded generator. Is that your proposal? 4 MR. WONG: Yes, I believe it is. We are 5 looking at small embedded generation to service load 6 growth within Ontario and rather than have the 7 transmission system expanded would be a justification 8 for that. 9 THE PRESIDING MEMBER: Now, in terms of the 10 12 megawatt -- the 20 megawatt limit that has been 11 talked about, why would we -- 20 megawatts is a good 12 number. Why not 10, not five, not anything? 13 MR. WONG: Well, I think our arguments pertain 14 really to all projects that are connected to the 15 distribution system and, from a practicality standpoint, 16 most of those projects are between the 5 and 20 megawatt 17 range. The distribution system simply isn't efficient 18 in connecting up to generators that are, say, higher 19 than 30 megawatts and typically the steam loads of 20 customers in these areas, like universities and 21 hospitals, wouldn't normally support a project higher 22 than that and meet Class 43 at the same time. 23 THE PRESIDING MEMBER: Okay. Just tell me, 24 what do you say, then, in the last bit there, that don't 25 meet code? 26 THE COURT REPORTER: Excuse me. Class 3? 27 MR. WONG: No, the Class 43 is a Revenue 28 Canada accelerated, high depreciation class. Les Services StenoTran Services Inc. 613-521-0703 2711 ENERGYLINK PANEL 1 1 To elaborate on that, for a given steam load 2 in order to meet Class 43, you can only produce so much 3 electricity. There is a ceiling on it. 4 THE PRESIDING MEMBER: Yes. 5 MR. WONG: Beyond that, you would basically 6 exceed -- you wouldn't fit into the 6,000 BT per 7 kilowatt hour criteria that is necessary to qualify for 8 Class 43. 9 THE PRESIDING MEMBER: Leaving aside the 10 embedded generation on the network, what happens if the 11 embedded generator decides to sell some power to the 12 market? 13 MR. WONG: Well, we are looking for net load 14 billing on the entire output of these plants. Typically 15 a portion of the electricity generated is sold through 16 the distribution system, either to the LDC or other 17 customers along the line. But since that doesn't 18 utilize the transmission system, that portion also ought 19 to be exempt or have net load billing applied to it. 20 Most of these plants aren't created for the 21 purpose of selling through the distribution system. It 22 is really there to service the direct connect customer, 23 the end customer. But because of its consumption 24 profiles there are times in the day and year in which 25 there is more electricity capable to be produced from 26 the plant. 27 From an economic standpoint, then, if that 28 power could be sold to other customers on the Les Services StenoTran Services Inc. 613-521-0703 2712 ENERGYLINK PANEL 1 1 distribution system, then it makes the economics more 2 attractive. 3 THE PRESIDING MEMBER: Just in terms of what 4 is there, the host steam load may not be available at 5 those times and may depend on the shift. Does that then 6 come to a problem with Revenue Canada? 7 MR. WONG: No. We take that into account in 8 the design of the system to accommodate the thermal 9 profile as well as the electricity consumption profile. 10 Even during times of low thermal demand, such as in the 11 afternoon in the summertime, in most cases, depending on 12 how you design the cycle, you could make use of that 13 excess steam and maybe generate a little more 14 electricity. It is all in the design of the system as 15 to how you meet with both those profiles for the end 16 customer. 17 THE PRESIDING MEMBER: The question I think is 18 why that should occur -- selling the power, that is -- 19 within the LDC versus selling outside back into the 20 grid. 21 MR. WONG: I think it just makes more 22 practical sense because these plants are located in high 23 consumption areas behind LDCs. The loads are there and 24 the customers are there, so there is no need to really 25 go through the transmission system to, say, other 26 regions to sell that power. And it is a small 27 proportion of the overall power that you generate. 28 THE PRESIDING MEMBER: Okay. Les Services StenoTran Services Inc. 613-521-0703 2713 ENERGYLINK PANEL 1 1 I think we have a better understanding of the 2 issues. Thank you very much for coming. I hope you 3 will have a safe trip back to Calgary. Thank you very 4 much. 5 MR. WONG: Thank you, Dr. Higgin. 6 THE PRESIDING MEMBER: We will take the 7 morning break and we will be back at 25 to 1100, please. 8 --- Upon recessing at 1102 9 --- Upon resuming at 1123 10 THE PRESIDING MEMBER: Okay. Mr. Budd. 11 MR. BUDD: Thank you, Dr. Higgin. 12 I would just like to introduce the witness 13 panel: Mr. Wayne Taylor, who is the Director of 14 Regulatory Affairs for TransAlta, sitting closest to the 15 Board; and, Mr. Stephen Hodgkinson, who is the Director 16 of Business Development with TransAlta, sitting further 17 from the Board. 18 If I could ask those two gentlemen to proceed 19 to be sworn by Mr. Smith. Thank you. 20 SWORN: WAYNE TAYLOR 21 SWORN: STEPHEN HODGKINSON 22 MR. BUDD: Thank you, Mr. Smith. 23 Mr. Chairman, I'm wondering if we can give 24 exhibit numbers to the curriculum vitae of the two 25 witnesses at this time. 26 MR. LYLE: We will mark those as 27 Exhibit G14.2. 28 EXHIBIT NO. G14.2: Curriculum vitaes of Les Services StenoTran Services Inc. 613-521-0703 2714 TRANSALTA PANEL 1 1 Wayne Taylor and Stephen Hodgkinson 2 MR. BUDD: Thank you, Mr. Lyle. 3 EXAMINATION-IN-CHIEF 4 MR. BUDD: I would like to turn to you, if I 5 could, first, Mr. Taylor, and just briefly review your 6 curriculum vitae. 7 Sir, I understand that you joined TransAlta in 8 1980 and have progressed through various management 9 positions in forecasting -- 10 MR. LYLE: One moment, Mr. Budd. 11 Are there extra copies? 12 MR. BUDD: They were at the side of the room 13 here. 14 MR. LYLE: I don't believe the panel have 15 copies. 16 --- Pause 17 THE PRESIDING MEMBER: Okay. 18 MR. BUDD: Thank you. 19 Mr. Taylor, I understand that you joined 20 TransAlta in 1980 and have progressed through various 21 management positions in forecasting, pricing, marketing, 22 retail services and regulatory affairs, and that prior 23 to joining TransAlta you worked for Bell Canada in 24 Montreal. Is that right? 25 MR. TAYLOR: That's correct. 26 MR. BUDD: Sir, I also understand that you 27 have a Bachelor and Master of Mathematics degrees from 28 the University of Waterloo and that you have completed Les Services StenoTran Services Inc. 613-521-0703 2715 TRANSALTA PANEL 1, in-ch (Budd) 1 the Executive Development Program at the University of 2 Calgary. 3 MR. TAYLOR: Yes, that's correct. 4 MR. BUDD: And that in your current role as 5 Director of Regulatory Affairs, you are responsible for 6 regulatory strategy, negotiating settlements with 7 stakeholders on regulatory matters and the management of 8 regulatory issues and events. Is that right? 9 MR. TAYLOR: Yes. 10 MR. BUDD: I also understand, sir, that you 11 have been TransAlta's policy witness on rate design and 12 customer service policy since 1985 and that you have 13 testified in regulatory proceedings before the Alberta 14 Energy Utilities Board and the British Columbia 15 Utilities Commission. Is that also correct? 16 MR. TAYLOR: That is correct. 17 MR. BUDD: And this is your first time 18 appearing before the Ontario Energy Board? 19 MR. TAYLOR: Yes. 20 MR. BUDD: I understand, sir, that you have 21 been extensively involved in the restructuring of the 22 electric industry in Alberta, that you have represented 23 TransAlta on various stakeholder teams throughout the 24 restructuring process, that you participated in the 25 drafting of the Electric Utilities Act and associated 26 regulations, and that you are a member of the Alberta 27 government's advisory committee on electricity industry 28 restructuring. Is that right? Les Services StenoTran Services Inc. 613-521-0703 2716 TRANSALTA PANEL 1, in-ch (Budd) 1 MR. TAYLOR: That's right. 2 MR. BUDD: Finally, sir, I understand that you 3 represented TransAlta in the establishment of the Grid 4 Company of Alberta, which was appointed the first 5 transmission administrator in Alberta, and that in your 6 role on the management committee of Gridco you over saw 7 the development of the current transmission tariff in 8 Alberta. Is that right? 9 MR. TAYLOR: That's correct. 10 MR. BUDD: Thank you for those answers. 11 Mr. Hodgkinson, if I could ask you some 12 questions, sir. 13 You hold a Bachelor of Applied Science degree 14 in Civil Engineering which you received in 1970. Is 15 that right? 16 MR. HODGKINSON: That's correct. 17 MR. BUDD: Since that time you have worked in 18 the consulting industry in Ontario for eight years and 19 in fact spent three years with Ontario Hydro planning 20 transmission lines and substations, sir. 21 MR. HODGKINSON: That's correct. 22 MR. BUDD: Thereafter you moved to Calgary in 23 1981 to join TransAlta Utilities where you progressed 24 through various management positions and planning 25 transmission facilities, regulatory approvals and 26 property administration. Is that right? 27 MR. HODGKINSON: Yes, it is. 28 MR. BUDD: Then you moved over to TransAlta Les Services StenoTran Services Inc. 613-521-0703 2717 TRANSALTA PANEL 1, in-ch (Budd) 1 Energy in 1990 to pursue development opportunities in 2 the independent power business. Is that correct? 3 MR. HODGKINSON: Yes. 4 MR. BUDD: And you have been involved and 5 worked on projects in Ontario for the past 10 years, 6 including negotiation of thermal sales contracts, power 7 purchase agreements, fuel supply and transportation 8 contracts as well as permitting and implementation of 9 cogeneration projects in Mississauga, Ottawa and 10 Windsor. Is that right? 11 MR. HODGKINSON: That's correct. 12 MR. BUDD: You opened a business development 13 office in Ontario and you moved back to Ontario in 1996 14 to pursue independent power opportunities. Is that 15 right? 16 MR. HODGKINSON: Yes, it is. 17 MR. BUDD: And you have also been involved in 18 the development of power projects in Quebec and in 19 Australia. 20 MR. HODGKINSON: That's correct. 21 MR. BUDD: Thank you. 22 Mr. Chairman, I take it these witnesses are 23 acceptable to the Board. Thank you. 24 Gentlemen, your prefiled evidence is marked as 25 Exhibit H-20-1 in the proceedings and your responses to 26 interrogatories filed as Exhibit E-20 series. Were you 27 jointly responsible for the preparation of TransAlta's 28 prefiled evidence and responses to interrogatories? Les Services StenoTran Services Inc. 613-521-0703 2718 TRANSALTA PANEL 1, in-ch (Budd) 1 MR. TAYLOR: Yes. 2 MR. HODGKINSON: Yes, we were. 3 MR. BUDD: Thank you. 4 Do you have any revisions, amendments or any 5 corrections you would care to make to your evidence and 6 responses to interrogatories? 7 MR. TAYLOR: No. 8 MR. HODGKINSON: No. 9 MR. BUDD: Thank you. 10 Do you therefore adopt your responses to 11 interrogatories and your prefiled evidence as your 12 evidence in this proceeding at this time? 13 MR. TAYLOR: Yes. 14 MR. HODGKINSON: Yes, we do. 15 MR. BUDD: Thank you. 16 Mr. Hodgkinson, I would like to turn to you 17 briefly, if I can, first and ask you to tell the Board 18 why is certainty important to an IPP developer? 19 MR. HODGKINSON: As in any other competitive 20 business, uncertainty creates risk. In our business 21 risk must be offset by the potential for reward. This 22 would normally manifest itself in a higher rate of 23 return for our shareholders and a higher rate of return 24 for our shareholders would in turn translate into the 25 pricing of our product and would affect our position in 26 the marketplace. 27 There are many risks associated with 28 independent power projects. These include construction, Les Services StenoTran Services Inc. 613-521-0703 2719 TRANSALTA PANEL 1, in-ch (Budd) 1 equipment costs, fuel, currency, the forward price of 2 electricity, among other things, and these risks are all 3 manageable. The one risk that is hard for us to manage 4 is regulatory risk because that is the one over which we 5 have the least control. 6 In developing cogeneration projects -- which 7 is what TransAlta does -- we make significant 8 investments, often extending into the hundreds of 9 millions of dollars, and our customers, in these 10 projects, are also making significant investment 11 decisions by agreeing to sign long-term contracts, which 12 are typically about 20 years in length, for the supply 13 of electrical and thermal energy. 14 In making these kinds of decisions, both 15 developers and customers need to weigh the risks that 16 are involved in any of the projects. An unstable or 17 uncertain regulatory environment makes these investment 18 decisions very difficult to make. 19 MR. BUDD: Thank you. 20 What kind of regulatory certainty are you 21 looking for, Mr. Hodgkinson? 22 MR. HODGKINSON: It is my understanding that 23 the OHNC application before this Board could deal with 24 rates for as little as a two-month period, following the 25 opening of the market. 26 We also understand that OHNC plans to submit a 27 further application dealing with the Years 2001 and 28 beyond. Les Services StenoTran Services Inc. 613-521-0703 2720 TRANSALTA PANEL 1, in-ch (Budd) 1 In our view, developers and customers alike 2 are looking to have the fundamental principles of this 3 competitive market established now so that investment 4 decisions can be made sooner rather than later. 5 We understand that transmission pricing may 6 change, from time to time, but we believe that the 7 fundamentals of the competitive market, including a 8 decision on gross versus net load billing, should be 9 established now and remain stable in the future. 10 MR. BUDD: Thank you, sir. 11 Mr. Taylor, if I could turn to you. 12 Would you please summarize TransAlta's 13 position on the issue of net versus gross load billing. 14 MR. TAYLOR: Yes. TransAlta is recommending 15 that the Board approve a combination of net load billing 16 for end-use customers and gross load billing for LDCs. 17 This combination of net and gross load billing is the 18 only proposal put forward in this proceeding that 19 achieves uniform transmission pricing for end-use 20 customers and, unlike the proposals put forward by OHNC 21 and OPGI, TransAlta's proposal does not discriminate 22 against load leaving the system due to the installation 23 of on site generation. 24 MR. BUDD: Sir, is it TransAlta's position 25 that existing load which leaves the system due to the 26 installation of on site generation should make no 27 contribution to the costs of the facilities constructed 28 to serve that customer's initial load? Les Services StenoTran Services Inc. 613-521-0703 2721 TRANSALTA PANEL 1, in-ch (Budd) 1 MR. TAYLOR: No. It is TransAlta's position 2 that existing load which leaves the system for any 3 reason -- and not just due to the installation of 4 on site generation -- should provide reasonable notice 5 of the reduction in load or should be required to make 6 an equivalent contribution in the absence of sufficient 7 notice. 8 The reason that gross load billing is not an 9 appropriate mechanism is that gross load billing only 10 recovers costs from existing load that leaves the system 11 due to the installation of on site generation and gross 12 load billing does not recover any costs from load that 13 leaves the system due to any other reason. 14 MR. BUDD: Thank you. 15 Now, notwithstanding the concern that gross 16 load billing does not recover any costs from load that 17 leaves the system due to any other reason, does gross 18 load billing collect a reasonable contribution from load 19 that leaves the system due to the installation of 20 on site generation? 21 MR. TAYLOR: In my view, the size of the 22 contribution needs to balance the interests of the 23 customer whose load is leaving the system and the 24 interests of all other customers. For example, if the 25 community gets together and replaces all of their 26 electric hot water heaters with natural gas hot water 27 heaters, the question is: For how long and at what 28 level should those customers be required to continue to Les Services StenoTran Services Inc. 613-521-0703 2722 TRANSALTA PANEL 1, in-ch (Budd) 1 pay for a delivery system that they are no longer using? 2 In my view, it is not reasonable to charge 3 them indefinitely, even at 50 per cent, for those 4 facilities that are no longer being used. 5 I also think that phasing out charges, from 6 100 per cent to 0 per cent, over 10 years, is also not 7 reasonable. 8 MR. BUDD: Thank you. 9 Now, doesn't TransAlta's proposal to use net 10 load billing for end-use customers but to use gross load 11 billing for LDCs discriminate against LDCs? 12 MR. TAYLOR: No. The appropriate test of 13 discrimination is at the end-use customer meter and the 14 combination of net load billing at the customer meter 15 and gross load billing at the LDC meter, as I said 16 earlier, is the only proposal in this proposal in this 17 proceeding which accomplishes uniform transmission 18 pricing at the end-use customer. 19 I did want to note, as an aside, counsel for 20 the MEA did point out, in cross-examination of OHNC, 21 that the use of 100 per cent gross load billing forever, 22 at both the customer meter and the end-use meter -- I 23 should say at the customer and the LDC meter, also does 24 accomplish uniform transmission pricing at the end-use 25 customer, and I do agree with his point. However, I 26 don't believe 100 per cent gross load billing forever is 27 fair or reasonable. I don't even think anyone in this 28 proceeding is putting that forward as a fair and Les Services StenoTran Services Inc. 613-521-0703 2723 TRANSALTA PANEL 1, in-ch (Budd) 1 reasonable proposal. But I wanted to note that the key 2 point is that, regardless of whether the end-use 3 customer is net or gross load billed, in order to 4 achieve uniform pricing at the end-use customer meter, 5 you need to use gross load billing at the LDC meter. 6 MR. BUDD: Thank you. 7 Do you agree that net load billing shifts cost 8 to customers who do not install embedded generation? 9 MR. TAYLOR: No, I don't. 10 First, any load leaving the system has an 11 impact on remaining customers, not just load which 12 leaves the system due to the installation of on site 13 generation. 14 Second, as I have already mentioned, it is our 15 position that load leaving the system for any reason, 16 including DSM, should make a reasonable contribution to 17 the costs of facilities installed to meet that 18 customer's initial load. 19 Third, it is true that because transmission 20 costs are largely fixed, in the short term, a reduction 21 in load, for any reason, will result in higher 22 transmission rates for all customers than would 23 otherwise be the case -- at least in the short term. 24 However, the converse is true, in the energy market; if 25 load on the system is reduced, the cost of energy from 26 the pool will be lower than it would otherwise have been 27 for all customers purchasing energy from the pool. The 28 net impact on customers of the higher transmission Les Services StenoTran Services Inc. 613-521-0703 2724 TRANSALTA PANEL 1, in-ch (Budd) 1 rates, on the one hand, and the lower energy costs, on 2 the other hand, could be positive or negative. 3 Finally, even ignoring the benefit of the 4 lower energy prices -- and particularly in TransAlta's 5 proposal where the LDCs are gross load billed and, 6 therefore, generation embedded behind the LDC meter has 7 no impact on transmission rates -- transmission rates 8 are going down and, as shown in Table 6L of Information 9 Response E-25 -- and there is no need to turn that up; 10 this is a table that Mr. Budd used in cross-examination 11 of the OHNC -- this table shows that the total range in 12 the forecast of transmission costs, in the Year 2008, 13 only varies by approximately 5 per cent. And as was 14 discussed previously in cross-examination, 5 per cent -- 15 5 per cent range transmission costs translates into less 16 than a 1 per cent change on a typical bundled customer 17 bill today. 18 In my view, these differences are not 19 material; they are not within the accuracy of the 20 forecast; and they certainly do not constitute rate 21 shock. Therefore, I do not believe there is any valid 22 reason to treat load leaving a system today -- because 23 there is surplus capacity on the transmission system 24 today -- any differently than we would treat load 25 leaving the system at any other point in time when there 26 wasn't the same amount of capacity on the transmission 27 system. 28 MR. BUDD: Now, do you agree that net load Les Services StenoTran Services Inc. 613-521-0703 2725 TRANSALTA PANEL 1, in-ch (Budd) 1 billing discriminates against merchant generation by 2 subsidizing embedded generation? 3 MR. TAYLOR: No, I don't. 4 The use of the term "subsidy" suggests that 5 net load billing would result in efficient investment 6 decisions being made in respect of on site generation. 7 To illustrate why that is not the case, let's assume a 8 manufacturer needs widgets as an intermediate product in 9 the production of the manufacturer's end product. If 10 the manufacturer has a choice between producing the 11 widgets on site at a cost of, say, $32, and that cost 12 includes all the costs for the purchase and delivery of 13 any of the raw materials required to produce the 14 widgets, and the manufacturer has a choice between 15 manufacturing these widgets on site at $32 or purchasing 16 these widgets on the market for $30 but then incurring a 17 $5 delivery charge to have the widgets delivered to his 18 site. 19 The rational economic decision for the 20 manufacturer to make is to make his own widgets. He can 21 make them on-site for 32 or buy at 30 and incur a $5.00 22 delivery charge. Clearly, the correct economic decision 23 is to manufacture them on-site. It would not be a 24 rational decision to ignore the delivery charge for the 25 purchased widgets, nor would it be rational to 26 unofficially add a delivery charge to the cost of making 27 widgets on-site and then comparing that cost to the 28 delivered cost of widgets purchased in the market. Les Services StenoTran Services Inc. 613-521-0703 2726 TRANSALTA PANEL 1, in-ch (Budd) 1 In our situation, customers who purchase 2 electricity from merchant generators need to have that 3 energy delivered and should pay for that delivery. 4 Customers who have on-site generation and, therefore, 5 don't require delivery, should not have to pay for 6 delivery. Net load billing results in efficient 7 investment decisions and does not constitute a subsidy 8 for embedded generation. 9 MR. BUDD: Sir, would that situation be 10 different for a manufacturer that is currently buying 11 widgets on the market but wants to start manufacturing 12 widgets on site? 13 MR. TAYLOR: In this case, to reach a rational 14 economic decision, the manufacturer should add to the 15 cost of making widgets on-site. Any cost to manufacture 16 would incur in terminating his contract to purchase 17 widgets in the market and have them delivered to his 18 site. 19 In our case, an existing customer who is 20 considering installing on-site generation and who cannot 21 give sufficient notice to avoid ratchets and minimums 22 should include in their economic analysis the cost that 23 will be incurred because of ratchet and minimum 24 provisions in the transmission tariff. 25 MR. BUDD: Sir, there have been a number of 26 references in this proceeding to transmission pricing in 27 Alberta. Would you please summarize the design of 28 transmission rates in Alberta. Les Services StenoTran Services Inc. 613-521-0703 2727 TRANSALTA PANEL 1, in-ch (Budd) 1 MR. TAYLOR: Yes. In Alberta we allocate 2 costs into just two pools, one pool for generators and 3 one pool for loads. Under our current rates, the only 4 costs that are allocated to generators are costs related 5 to the interconnection facilities of the existing 6 regulated units. 7 My understanding is that there have been no 8 costs allocated to generated in this proceeding, so I 9 will focus my remarks on the costs allocated to loads. 10 One difference for loads between Alberta and 11 Ontario is that in Alberta we only have one cost pool 12 compared to the three that are put forward in this 13 proceeding. Another difference, however, is we classify 14 this one pool of cost between non-coincident demand and 15 on-peak energy. 16 The reason that some costs are classified 17 based on NCP is to recognize that local or connection 18 facilities dedicated to one or a few customers are 19 generally sized to meet the non-coincident demand of 20 each customer. The reason that some costs are 21 classified based on on-peak energy is to recognize that 22 the bulk or network system facilities are generally 23 sized to meet the system's coincident peak. 24 In Alberta we use on-peak energy which is 25 defined as 8:00 a.m. top 9:00 p.m. weekdays as a proxy 26 for a customer's contribution to coincident peak demand 27 which we believes provides a reasonable price signal to 28 both high and low load factor customers. Les Services StenoTran Services Inc. 613-521-0703 2728 TRANSALTA PANEL 1, in-ch (Budd) 1 When we developed our first transmission 2 tariff in Alberta, we proposed a 50-50 classification 3 between NCP and non-peak energy in recognition of the 4 continuum between connection facilities and network 5 facilities. 6 Ratchets and minimums apply to the NCP charge 7 which generally recovers the cost of connection 8 facilities, but do not apply to the on-peak energy 9 charge which generally recovers the cost of network 10 facilities. As well, customers can give notice to avoid 11 some or all of the ratchets and minimums associated with 12 the NCP charge. 13 At the present time in Alberta, we have the 14 same combination of net load billing for end use 15 customers and gross load billing for LDCs as TransAlta 16 has put forward in this proceeding. This combination of 17 net and gross load billing was implemented to achieve 18 uniform pricing for transmission service at the end use 19 customer. 20 Also, in Alberta, we do not have, and in my 21 view do not require, a separate rate for backup. 22 Customers requiring backup through the NCP charge and 23 associated ratchets will pay for the local facilities 24 required to provide the backup service and through the 25 on-peak energy charge will pay a fair share of the deep 26 or bulk network facilities, recognizing their relatively 27 low load factor. 28 MR. BUDD: Finally, Mr. Taylor, the Alberta Les Services StenoTran Services Inc. 613-521-0703 2729 TRANSALTA PANEL 1, in-ch (Budd) 1 Regulator last month issued its decision on new 2 transmission tariffs which will go into effect this 3 spring. Two excerpts from this decision are in 4 evidence. Do you have any comments on that decision? 5 MR. TAYLOR: Yes. I would like to briefly 6 comment on each excerpt. The first excerpt that was 7 introduced, which was Exhibit T2.2, refers to the issue 8 of gross versus net load billing. As I mentioned 9 earlier, under the current tariff in Alberta, end use 10 customers are net load billed and LDCs are gross load 11 billed. 12 In this decision, the Regulator approved a 13 change to net load billing for LDCs. However, I wanted 14 to clarify that this is a change in mechanics and not a 15 change in intent nor result. The reason is that the 16 Regulator also directed that the LDCs pay to any 17 embedded generator the difference between what the LDC 18 would have paid to the transmission administrator under 19 gross load billing and what the LDC will now pay to the 20 transmission administrator under net load billing. 21 As a result, the LDC is still incurring on 22 behalf of its load customers the same total transmission 23 charge. Therefore, the LDCs are still effectively gross 24 load billed and the result is still uniform transmission 25 pricing at the end use customer. Only the mechanics 26 have changed. 27 The second excerpt which is in evidence as 28 Exhibit G4.1, sets out the ratchet provisions which have Les Services StenoTran Services Inc. 613-521-0703 2730 TRANSALTA PANEL 1, in-ch (Budd) 1 been approved in Alberta. I wanted to point out two 2 things. First, as I mentioned earlier, the ratchet only 3 applies to the NCP charge, not the on-peak energy charge 4 and the NCP charge under the Alberta Regulator's recent 5 decision will recover approximately 35 per cent of the 6 transmission revenue requirement. 7 In other words, if load left the system and 8 was subject to the ratchets as set out in this decision, 9 the portion of the revenue requirement that would be 10 subject to the ratchets would start at 35 per cent and 11 phase out over five years. 12 The second thing I wanted to just say again is 13 that even with this ratchet and notice provisions, a 14 customer can give notice in Alberta to avoid some or all 15 of the ratchet and minimum provisions in our tariff. 16 That concludes my direct evidence. 17 MR. BUDD: Thank you, Mr. Taylor and Mr. 18 Hodgkinson. 19 Mr. Chairman, the witnesses are now available 20 for cross-examination. 21 THE PRESIDING MEMBER: Thank you. 22 Mr. Fisher. 23 MR. FISHER: I have no questions, Dr. Higgin. 24 Thank you. 25 THE PRESIDING MEMBER: Mr. Adams. 26 CROSS-EXAMINATION 27 MR. ADAMS: Thank you. Just a few very brief 28 questions. Les Services StenoTran Services Inc. 613-521-0703 2731 TRANSALTA ENERGY PANEL 1, cr-ex (Adams) 1 With the previous witness I asked a question 2 as to what portion of the delivered cost of energy from 3 his projects as a rule of thumb related to fuel cost. I 4 would like to ask the same question to you with regard 5 to the project you are planning for Sarnia. What 6 portion is fuel cost of the delivered cost of energy, 7 just in general terms? I'm not looking for specific 8 numbers. 9 MR. HODGKINSON: That's good because I don't 10 have a specific number. I would guess it would be in 11 the order of 70 per cent. 12 MR. ADAMS: So, a somewhat greater portion of 13 the cost of delivered power from your project would 14 relate to fuel costs relative to that that the previous 15 witness spoke of with smaller projects. Is that fair? 16 MR. HODGKINSON: I think that's fair. Fuel is 17 our biggest single expense on a cogeneration project. 18 MR. ADAMS: I asked a question of the previous 19 witness: What reduction in gas prices would it take to 20 net out for you to the same delivered cost of energy 21 benefit relative to your proposal for net load billing 22 as compared with a full gross load billing tariff? 23 MR. HODGKINSON: I have no idea. I'm afraid I 24 don't understand the question at all. 25 MR. ADAMS: Let me take it in pieces. 26 Gas prices correspond to a large portion of 27 your delivered cost of electrical energy. 28 MR. HODGKINSON: That's correct. Les Services StenoTran Services Inc. 613-521-0703 2732 TRANSALTA ENERGY PANEL 1, cr-ex (Adams) 1 MR. ADAMS: Under gross load billing, your 2 customers will see a certain price for power and that 3 relates to their cost of your delivered power plus the 4 cost of transmission. 5 MR. HODGKINSON: Are you talking about any 6 particular customers? Is this a generic project? 7 MR. ADAMS: I am thinking in terms of the 8 Sarnia cogeneration project. 9 MR. HODGKINSON: I think the project that we 10 have been working on in Sarnia is a little unlike most 11 typical embedded generation projects because of the 12 existence of existing embedded generation. So I'm not 13 sure it quite fits the question you are asking. 14 MR. ADAMS: What is the distinction? 15 Maybe I'm not understanding your 16 clarification. 17 MR. HODGKINSON: Well, as I understand it, on 18 OHNC application, existing embedded generation would be 19 grandfathered and eligible for net load billing. 20 MR. ADAMS: Okay. And the existing -- what 21 portion of your Sarnia project is existing generation? 22 MR. HODGKINSON: I am a little reluctant to 23 get into much detail about that project because we are 24 in the midst of confidential discussions with our 25 customers. We have no agreements concluded and all of 26 our discussions around the Sarnia project are covered by 27 confidentiality agreements so I am little reluctant to 28 discuss that. Les Services StenoTran Services Inc. 613-521-0703 2733 TRANSALTA ENERGY PANEL 1, cr-ex (Adams) 1 MR. ADAMS: Can you tell me what the impact on 2 your business would be of a gross load tariff decision 3 by this Board relative to your proposals? 4 MR. HODGKINSON: Well, I guess when the 5 project was first envisioned by the Sarnia Economic 6 Development Council, I think we all believed that there 7 would be some form of net load billing regime. 8 I'm not sure I can comment specifically on 9 what a gross load decision would mean until I saw that 10 decision in detail, but we would certainly have to 11 re-evaluate our position in Sarnia and see if the 12 project still made sense in light of whatever ruling 13 comes out. 14 MR. ADAMS: Of course you would. 15 But can you give you me an illustrative 16 guideline as to the impact on your project? 17 MR. HODGKINSON: As I said, the project is 18 just a concept at this point until agreements are 19 reached with the customers. So until that happens I 20 don't have a project and I really can't comment on what 21 the impacts would be one way or the other. 22 MR. TAYLOR: Mr. Adams, if it is helpful, in 23 response to one of the interrogatories we got from 24 Energy Probe, No. 3, which is part of, I believe, the 25 E-20 series -- this, admittedly, is a hypothetical 26 example, but I did show that for a typical 100 megawatt 27 embedded generator under OHNC -- and assuming the 28 generator is efficient so it qualifies for the Les Services StenoTran Services Inc. 613-521-0703 2734 TRANSALTA ENERGY PANEL 1, cr-ex (Adams) 1 50 per cent -- using some typical capacity factors and 2 an average transmission tariff of $5.00 a megawatt hour, 3 I showed there that the cost to the project of having to 4 pay for that 50 per cent access fee, or whatever we are 5 calling here, is about $1.5 million per year. That was 6 just randomly picking 100 megawatt size. 7 MR. VLAHOS: I'm sorry, sir, I missed the 8 number. What was the number, the dollar number? 9 MR. TAYLOR: One-point-five million per year. 10 MR. VLAHOS: Thank you. 11 MR. ADAMS: I'm interested in your comment 12 previously that when had been developing your project 13 you were operating on the assumption that there would be 14 a net load tariff. 15 Are you familiar with the report of the Market 16 Design Committee with regard to its recommendations for 17 transmission pricing? 18 MR. HODGKINSON: I am generally familiar with 19 the MDC report, yes. 20 MR. ADAMS: And the MDC recommended gross load 21 billing? 22 MR. HODGKINSON: That's correct. 23 I might point out that that was just that, a 24 recommendation. As I understand it, that recommendation 25 wasn't accepted by the government and that is part of 26 the reason we are all here to today. 27 MR. ADAMS: The recommendation wasn't accepted 28 by the government? Les Services StenoTran Services Inc. 613-521-0703 2735 TRANSALTA ENERGY PANEL 1, cr-ex (Adams) 1 MR. HODGKINSON: As far as I know or as I 2 understand it, the instructions from the Minister of 3 Energy were to re-examine alternatives to gross load 4 billing. My interpretation is that that recommendation 5 was not accepted as presented. 6 MR. ADAMS: So is the decision -- is it your 7 position that the decision on this tariff application is 8 to be made by the government, not this Board? 9 MR. HODGKINSON: No, I believe it is being 10 made by this Board. 11 MR. ADAMS: What is your understanding of the 12 role of the government in this decision? 13 MR. HODGKINSON: No. I'm just talking about 14 the Market Design Committee report. 15 My whole point was that that report was only a 16 recommendation. It was never adopted in total by 17 anyone. 18 MR. ADAMS: You are a member of IPPSO? 19 MR. HODGKINSON: Yes, we are. 20 MR. TAYLOR: Yes, we are. 21 MR. ADAMS: Your company? 22 MR. HODGKINSON: Yes we are. 23 MR. ADAMS: IPPSO is a member of the Market 24 Design Committee? 25 MR. HODGKINSON: I'm not quite sure I know the 26 answer to that. I don't know the answer to that. 27 MR. ADAMS: Former IPPSO President 28 Steve Probyn(ph) was a member of the Market Design Les Services StenoTran Services Inc. 613-521-0703 2736 TRANSALTA ENERGY PANEL 1, cr-ex (Adams) 1 Committee. 2 MR. HODGKINSON: Fine. I recognize the name. 3 MR. ADAMS: I have no further questions. 4 THE PRESIDING MEMBER: Thank you, Mr. Adams. 5 Ms Friedman, would you like to come up? 6 --- Pause 7 MS FRIEDMAN: All this for one question. 8 CROSS-EXAMINATION 9 MS FRIEDMAN: I am looking at page 5 of your 10 prefiled evidenced at lines 28 to 30. I will just read 11 it into the record if you can't get it up quickly 12 enough. 13 "TransAlta therefore recommends that the 14 Board adopt gross load billing at the MEU 15 meter to give effect to postage stamp 16 transmission at the retail customer and 17 to ensure a level playing field between 18 IP projects located inside or outside of 19 an MEU." (As read) 20 I'm just trying to reconcile that desire that 21 you have expressed to ensure a level playing field 22 between IP projects located inside or outside of an MEU. 23 I am trying to reconcile that with what you said about 24 the Alberta decision. I am not sure if you support the 25 Alberta decision or you don't. 26 You said that in Alberta, the decision has 27 been made to gross load bill at the MEU meter and then 28 the MEU gives that payment over, the difference between Les Services StenoTran Services Inc. 613-521-0703 2737 TRANSALTA PANEL 1, cr-ex (Friedman) 1 net and gross load billing, to the embedded generator. 2 MR. TAYLOR: That's correct. 3 MS FRIEDMAN: Would you agree that that gives 4 an incentive to IP projects to locate within the MEU? 5 MR. TAYLOR: Let me clarify one further thing 6 about Alberta is that the entire service area is covered 7 by one LDC or another. There is no equivalent of OHNCD. 8 So TransAlta Utilities is considered to be an 9 LDC in our distribution service area and so we are 10 treated at each point of delivery off the transmission 11 system the same as the City of Calgary is, which is, I 12 think what you would consider muni or an MEU. 13 So in Alberta this level playing field is 14 achieved because TransAlta and Alberta Power, now ATCO, 15 also are treated the same way. For every point of 16 delivery that we have off the transmission system, if 17 there is an embedded generator beyond that we have to 18 pay to that embedded generator -- or will have to pay 19 under the new tariff -- the difference between what our 20 gross bill would have been to the transmission 21 administrator and what our net bill will now be. 22 So we don't have the same situation where 23 there is different treatment within municipalities and 24 outside municipalities. 25 MS FRIEDMAN: All right, then. So you are 26 telling me that you support the goal of the level 27 playing field inside and outside of an MEU Ontario. 28 Alberta doesn't have the same situation, so we would Les Services StenoTran Services Inc. 613-521-0703 2738 TRANSALTA PANEL 1, cr-ex (Friedman) 1 have to fine-tune the proposal to deal with the Ontario 2 situation. 3 MR. TAYLOR: I believe our proposal does 4 address that concern in Ontario as it does in Alberta. 5 MS FRIEDMAN: Thank you. 6 THE PRESIDING MEMBER: Mr. Campbell? 7 CROSS-EXAMINATION 8 MR. CAMPBELL: Mr. Taylor, I think my question 9 is for you, and it is simply this. 10 Can you confirm for me, please, what I 11 understand from the recent Alberta decision, which is 12 that there are serious constraints that have developed 13 with respect to transmission capacity on the Alberta 14 interconnected electrical system, and then, in 15 particular, the evidence in that proceeding was clear 16 that the most pressing problem facing that system is the 17 risk of voltage collapse in southern Alberta, caused by 18 lack of reactive power in southern Alberta, and growing 19 constraint on the main Edmonton-Calgary transmission 20 line? 21 MR. TAYLOR: I agree with all of that except 22 for your opening comment that there are several 23 constraints. I forget how you worded that. There is a 24 constraint on the Alberta system which is the constraint 25 that you referred to. There is a constraint in the 26 Calgary area right now that is being addressed right 27 now. 28 Most other areas of the province do not face Les Services StenoTran Services Inc. 613-521-0703 2739 TRANSALTA PANEL 1, cr-ex (Campbell) 1 similar constraints. 2 MR. CAMPBELL: Would you agree with me that 3 the Board in Alberta described the constraints on the 4 Alberta system as "serious constraints" that have 5 developed with respect to transmission capacity? 6 MR. TAYLOR: The constraint in the Calgary 7 area is a serious constraint, yes. 8 MR. CAMPBELL: I think that wasn't quite my 9 question. 10 If you have the Alberta decision you could 11 refresh your memory by looking at page 125, but I just 12 want you to confirm, please, that in the view of the 13 Board, at the top of that page they say, "serious 14 constraints have developed with respect to transmission 15 capacity on that system"? 16 MR. TAYLOR: Right. But if you go on to read 17 the next sentence, sir, it says: 18 "In particular, the evidence is very 19 clear that the most pressing current 20 problem facing the AIES..." (As read) 21 Which stands for the Alberta Interconnected 22 Electrical System: 23 "...is the risk of voltage collapse in 24 southern Alberta caused by the lack of 25 reactive power in southern Alberta and 26 the growing constraint on the main 27 Edmonton-Calgary transmission line." 28 (As read) Les Services StenoTran Services Inc. 613-521-0703 2740 TRANSALTA PANEL 1, cr-ex (Campbell) 1 That is a single problem. We have a lack of 2 capacity into the Calgary area, that is true. There are 3 no other similar serious constraints in Alberta at the 4 present time. 5 MR. CAMPBELL: Thank you. 6 Thank you, Mr. Chairman. Those are my 7 questions. 8 THE PRESIDING MEMBER: Thank you, 9 Mr. Campbell. 10 Board staff? 11 MR. LYLE: Thank you, Mr. Chair. 12 EXAMINATION 13 MR. LYLE: Gentlemen, if I could just refer 14 you to your prefiled evidence, page 3. At line 29 you 15 state that: 16 "...requiring a customer who reduces load 17 to continue to pay indefinitely for 18 facilities which the customer is no 19 longer using is neither fair nor 20 reasonable." 21 Given that, do you understand OPGI's proposal 22 in this proceeding? 23 MR. TAYLOR: I believe so. 24 MR. LYLE: Do you have any preference for 25 OPGI's proposal over OHNC's proposal given that OPGI's 26 proposal over time would phase out gross load billing 27 on a -- 28 MR. TAYLOR: I think that -- Les Services StenoTran Services Inc. 613-521-0703 2741 TRANSALTA PANEL 1, ex (Lyle) 1 MR. LYLE: -- sorry -- on a project-specific 2 basis? 3 MR. TAYLOR: I think, as I said in my direct, 4 that both proposals treat load leaving the system unduly 5 harshly. Whether it is 50 per cent forever or at least 6 until we start negotiating contracts or something, or 7 100 per cent phasing out over 10 years, in my view both 8 of those are unfair and unreasonable to load leaving the 9 system. 10 I believe, if memory serves me correctly, even 11 in one of the OPGI interrogatory responses, I believe it 12 was pointed out that on a present value basis those are 13 roughly the same impact on customers. So I don't think 14 those are significantly different alternatives in terms 15 of the impact on a load leaving the system and I think 16 they are both too harsh. 17 MR. LYLE: I just want to clarify your 18 proposal for gross load billing for the MEUs, sir. As I 19 understand it, the MEUs would be gross load billed but 20 there would be no attempt to essentially pass on that 21 gross-up portion of the bill to the embedded generators. 22 Then with other transmission customers who aren't MEUs, 23 they would be net load billed. Is that basically your 24 proposal? 25 MR. TAYLOR: That's right. But just to be 26 clear, any end-use customer, whether they are a 27 transmission customer or connected at the distribution 28 system, in my view, should be net load billed. At the Les Services StenoTran Services Inc. 613-521-0703 2742 TRANSALTA PANEL 1, ex (Lyle) 1 LDC meter, what we should do is take obviously the 2 reading at the LDC meter and add back in hour by hour 3 any net inflows into the LDC system from generation that 4 is embedded within the LDC but only add in the net 5 flows, net inflows that occur at their customer meters. 6 I'm trying to be clear here. If you had an 7 embedded generator that was on a customer's plate within 8 the MEU that was just displacing that customer's load, 9 and let's say just equally matching that customer's 10 load, that would have no impact and we would not add any 11 of that energy back to the LDC meter. We would only add 12 back onto the LDC meter reading any net inflows into the 13 LDC system. That is how you make the arithmetic work to 14 get uniform transmission pricing at the end-use customer 15 meter. 16 MR. LYLE: I see. So it would have to be the 17 embedded generator actually putting power into the 18 distributor's system, is it? 19 MR. TAYLOR: That's correct. That's exactly 20 right. 21 MR. LYLE: I see. 22 How would you treat OHNC's distribution arm? 23 --- Pause 24 MR. TAYLOR: I hadn't thought about that, to 25 be honest. I think that, as I just explained, the way 26 we treat that in Alberta is we would treat each point of 27 delivery to OHNCD in the same manner and charge OHNCD as 28 if they were an LDC in my example. That is how we do it Les Services StenoTran Services Inc. 613-521-0703 2743 TRANSALTA PANEL 1, ex (Lyle) 1 in Alberta and I believe that would be appropriate in 2 Ontario as well. 3 MR. LYLE: One moment. 4 --- Pause 5 MR. LYLE: I just want to turn finally, sir, 6 to the issue of liability, which you have raised. I 7 want to refer you to OHNC's prefiled evidence at 8 Exhibit D, Tab 12, Schedule 2. 9 MR. BUDD: And the page reference? 10 MR. LYLE: That is page 17. 11 --- Pause 12 MR. TAYLOR: I have that. 13 MR. LYLE: At 3.7 it states "Limitation of 14 Liability". It goes from line 15 to 18. I understand 15 that is the clause that you are objecting to. 16 MR. TAYLOR: Yes. 17 MR. LYLE: In your view, this provision would 18 mean that OHNC would not be liable and negligent for any 19 failures in the transmission system. Is that your 20 understanding? 21 MR. TAYLOR: I can't give you a legal opinion, 22 but it is my lay understanding, yes. 23 MR. LYLE: Do you have any familiarity with 24 the terms of conditions in the orders of gas 25 distributors in Ontario? 26 MR. TAYLOR: I do not, no. 27 MR. LYLE: Thank you. Those are all my 28 questions. Les Services StenoTran Services Inc. 613-521-0703 2744 TRANSALTA PANEL 1, ex (Lyle) 1 THE PRESIDING MEMBER: Thank you, Mr. Lyle. 2 Mr. Rogers. 3 MR. ROGERS: Thank you. 4 CROSS-EXAMINATION 5 MR. ROGERS: Gentlemen, could you help me 6 understand the organization of the utility business in 7 Alberta, the electrical utility business in Alberta? 8 First of all, Mr. Taylor, do I understand that 9 you are employed by -- which TransAlberta company are 10 you employed by? 11 MR. TAYLOR: I work for TransAlta Corporation. 12 Just to explain, TransAlta Corporation, we have two 13 principal subsidiaries, fully owned. One is called 14 TransAlta Utilities, which is the traditional bundled 15 integrated Alberta utility, and one which is called 16 TransAlta Energy, which is a subsidiary in which we have 17 done our IPP investments around the world. 18 I'm actually in the parent TransAlta 19 Corporation. The parent has corporate services that are 20 provided to both the utility side and the energy side. 21 MR. ROGERS: All right. 22 MR. TAYLOR: But you can treat it as a 23 single -- 24 MR. ROGERS: The company that you work for, it 25 sounds like it is a holding company of some type. But 26 what I'm really interested in is your role here today. 27 I understand you are in charge of regulatory affairs for 28 one of these companies. Right? Les Services StenoTran Services Inc. 613-521-0703 2745 TRANSALTA PANEL 1, cr-ex (Rogers) 1 MR. TAYLOR: That is right. I am in TransAlta 2 Corporation, which is the parent company of both 3 utilities, TransAlta Utilities and TransAlta Energy. 4 MR. ROGERS: Right. You are the Director of 5 Regulatory Affairs for the transmission company? 6 MR. TAYLOR: For TransAlta Corporation. 7 MR. ROGERS: Okay. TransAlta Corporation. 8 Now, is that a -- tell us about that. That 9 has transmission facilities in Alberta? 10 MR. TAYLOR: TransAlta Utilities has 11 generation, transmission, distribution and retail 12 facilities in Alberta -- retail operations. 13 MR. ROGERS: Does TransAlta Utilities also own 14 generation facilities? 15 MR. TAYLOR: In Alberta. 16 MR. ROGERS: In Alberta? 17 MR. TAYLOR: Yes. 18 MR. ROGERS: So the one company, then, in 19 Alberta, has, either directly or through its 20 subsidiaries, it doesn't really matter, but you provide 21 generation of electricity, transmission of electricity 22 and distribution of electricity? 23 MR. TAYLOR: And retail operations, yes, sir. 24 MR. ROGERS: And retail operations, as well? 25 MR. TAYLOR: Correct. 26 MR. ROGERS: How many electric companies are 27 there in Alberta like that? 28 MR. TAYLOR: Well, there are four that have Les Services StenoTran Services Inc. 613-521-0703 2746 TRANSALTA PANEL 1, cr-ex (Rogers) 1 all of those functions and there are a number of others 2 that are just distributors and retailers -- 3 municipalities similar to what you have here in Ontario. 4 MR. ROGERS: I see. All right. And do you 5 work on, like, franchise areas like our gas utilities 6 do? 7 MR. TAYLOR: We have franchise areas for our 8 distribution system. 9 MR. ROGERS: So your company, TransAlta, would 10 have a distribution system for electricity? 11 MR. TAYLOR: That is correct. 12 MR. ROGERS: Where is that? 13 MR. TAYLOR: Generally, the southern 14 two-thirds of the province is our service area. 15 MR. ROGERS: I see. 16 MR. TAYLOR: With the exception of the large 17 municipalities of Calgary, Edmonton, Red Deer, 18 Lethbridge, Medicine Hat. 19 The large municipalities all own their own 20 distribution systems, similar to the situation in 21 Ontario. 22 MR. ROGERS: Thank you. That helps me 23 somewhat. 24 Now, Mr. Hodgkinson, you are here today as a 25 representative of TransAlta Energy Corporation. Right? 26 MR. HODGKINSON: That is correct. 27 MR. ROGERS: And you are interested in these 28 proceedings because your company wants to develop Les Services StenoTran Services Inc. 613-521-0703 2747 TRANSALTA PANEL 1, cr-ex (Rogers) 1 generation projects here in Ontario? 2 MR. HODGKINSON: That is correct. 3 MR. ROGERS: Otherwise, you wouldn't be here, 4 I guess? 5 MR. HODGKINSON: Well, our company has been in 6 Ontario for the last 10 years, in the generation 7 business, and has every intention of, under the right 8 conditions, making this a permanent base of operations. 9 MR. ROGERS: Oh, no. We are very glad to have 10 you here. Don't misunderstand me. But -- 11 --- Laughter 12 MR. ROGERS: -- the point is that you are here 13 giving evidence today not because you want to help us 14 out in Ontario but because you want to develop energy 15 projects here in Ontario? 16 MR. HODGKINSON: Clearly, yes. 17 MR. ROGERS: I understand. 18 Now, help me, gentlemen, if you would, with 19 the situation in Alberta, generally. 20 Mr. Taylor, perhaps you are the best one for 21 this. 22 Can you tell me what is the approximate peak 23 demand, in megawatts, in Alberta? 24 MR. TAYLOR: Approximately 7,000. 25 MR. ROGERS: What is the approximate installed 26 capacity of generation in Alberta? 27 MR. TAYLOR: I don't have that with me. I 28 would have to -- if that was important to you, I could Les Services StenoTran Services Inc. 613-521-0703 2748 TRANSALTA PANEL 1, cr-ex (Rogers) 1 undertake to dig that up. 2 MR. ROGERS: Well, the reason I ask -- it may 3 be; I don't think we need details on it -- but I 4 understand, from the newspapers, over the past several 5 years, that there have been supply constraints in 6 Alberta. Is that correct? 7 MR. TAYLOR: Supply/demand situation in 8 Alberta, particularly last year, was quite tight. 9 There has been significant generation added 10 this year, so the supply/demand balance is not as tight 11 this year as it was last year. 12 MR. ROGERS: But over the past few years, at 13 least, it is fair to say, then, that you have had a 14 shortage of generation? 15 MR. TAYLOR: Particularly last year. 16 MR. ROGERS: Did you have some brown-outs last 17 year? 18 MR. TAYLOR: We had -- if memory serves me 19 correctly, we had one interruption of firm load, as a 20 result of generation shortage. 21 MR. ROGERS: So it has been a very tight 22 situation on generation? 23 MR. TAYLOR: It was tight. 24 As I say, there has been significant 25 generation added this year, so it is not nearly as 26 constrained this year. 27 MR. ROGERS: What was added this year? 28 MR. TAYLOR: There were a number IPP projects Les Services StenoTran Services Inc. 613-521-0703 2749 TRANSALTA PANEL 1, cr-ex (Rogers) 1 added this year. 2 As you know, we only -- there is no more 3 regulated generation being constructed in Alberta. 4 January 1, 1996, was the end of regulated generations. 5 All the new projects that have been constructed are IPP 6 projects. 7 MR. ROGERS: How many megawatts have been 8 added? 9 MR. TAYLOR: Again, I don't have those details 10 with me. It has been a few hundred. But I couldn't -- 11 again, if it is important, I could undertake to find 12 out -- 13 MR. ROGERS: Well, no, I don't think the 14 details are that important. 15 What I wanted to understand, or have confirmed 16 was my understanding that there has been a problem with 17 generation meeting this demand in Alberta -- and you 18 have confirmed that and you said that there has been a 19 few hundred megawatts added which have alleviated the 20 situation somewhat. 21 MR. TAYLOR: That is correct. 22 MR. ROGERS: What has been the load growth in 23 Alberta, on average, over the past -- well, let's say in 24 the nineties? Can you help us with that? 25 MR. TAYLOR: Again, I have all this material 26 in my office; I didn't bring it with me. I would be 27 glad to undertake -- it would be on the order of, 28 probably, 2 per cent a year. Maybe a little higher. Les Services StenoTran Services Inc. 613-521-0703 2750 TRANSALTA PANEL 1, cr-ex (Rogers) 1 If you need an exact number, I would be glad 2 to undertake to get that for you. 3 MR. ROGERS: Could you do that for me, please? 4 I would be interested in the average load growth over 5 the past -- let's say in the 1990s. 1990 to date. The 6 past 10 years. 7 MR. LYLE: We will mark that as 8 Undertaking F14.1. 9 UNDERTAKING NO. F14.1: Mr. Taylor to 10 undertake to provide the average load 11 growth and the generation that has been 12 added, for the period 1990 to date, on a 13 year-by-year basis 14 MR. TAYLOR: Since I have gotten myself into 15 an undertaking, would you also like me to add on to that 16 the generation that has been added, to answer your 17 previous question? 18 MR. ROGERS: Please, if you wouldn't mind, 19 when you go back, yes. Thank you. 20 So, just for the purposes of our discussion, 21 can I assume that it has been in the order of 2 or 3 per 22 cent, over that period of time? Is that what you said? 23 MR. TAYLOR: For the purposes of discussion, I 24 am prepared to accept that. I will get you the exact 25 numbers in the undertaking. 26 MR. ROGERS: All right. I have been asked by 27 one of my colleagues to request that you provide that 28 data year by year. Les Services StenoTran Services Inc. 613-521-0703 2751 TRANSALTA PANEL 1, cr-ex (Rogers) 1 Would you do that, Mr. Taylor? 2 MR. TAYLOR: I could do that. 3 MR. ROGERS: Thank you. 4 So you have had, I would say, fairly 5 substantial load growth, then, on a cumulative basis, 6 over the past decade. 7 MR. TAYLOR: Certainly, the Alberta economy 8 has been more robust than some provinces, yes, sir. 9 MR. ROGERS: Including Ontario. 10 MR. TAYLOR: I don't know what Ontario's has 11 been, but I will accept that, if that is correct. 12 MR. ROGERS: Well, recently, it is a little 13 better but... 14 In Alberta, Mr. Taylor, what is the definition 15 of the boundary between transmission and distribution? 16 MR. TAYLOR: It is a little complicated, but 17 to put it simply: it is the low voltage side of the 18 substation which transforms energy from voltages of 19 above 25 kV to voltages of 25 kV or below. 20 MR. ROGERS: So it is 25 kV, in Alberta? 21 MR. TAYLOR: 25 kV in Alberta is distribution. 22 And the substation that gets you between 25 kV 23 and, say, 138 kV, in our system, is considered 24 transmission. 25 MR. ROGERS: All right. Thank you. 26 What is the maximum size of a generating plant 27 that can be connected to a 25-kV system? Rule of thumb. 28 MR. TAYLOR: Well, it depends, of course, Les Services StenoTran Services Inc. 613-521-0703 2752 TRANSALTA PANEL 1, cr-ex (Rogers) 1 where you are located on the system and how strong the 2 system is and that sort of thing. 3 You could probably -- I know that, on the load 4 side, we can connect loads as high as 50 megawatts to a 5 distribution system. Much more than and you probably 6 need to be connected to the transmission system. 7 MR. ROGERS: You can connect a 50-megawatt...? 8 MR. TAYLOR: It depends where you are and how 9 strong the system is and how close you are to system 10 sources and that sort of thing. 11 That would certainly be the high end. 12 MR. ROGERS: Mr. Hodgkinson, I don't want you 13 to disagree with your colleague, necessarily, but you 14 are an engineer, I think. 15 Do you have any help for me there? 16 MR. HODGKINSON: I am a civil engineer. Would 17 you like a bridge? 18 --- Laughter 19 MR. TAYLOR: I should -- if I wasn't clear, 20 Mr. Rogers, I was saying, from a load point of view -- 21 and I have dealt with, over many years, customer 22 contracts where there has been new loads connected -- 23 from a load point of view, I know we have been able to 24 connect loads of that size to the distribution system. 25 If it was in a location of the province where there was 26 a strong 25 kV source -- I should be a little careful 27 here, I am making the assumption that that would 28 translate into a generator, as well; I don't know that. Les Services StenoTran Services Inc. 613-521-0703 2753 TRANSALTA PANEL 1, cr-ex (Rogers) 1 MR. ROGERS: All right. I just was surprised 2 at the size, but perhaps that is my misunderstanding. 3 Are there other major utilities in Alberta 4 that provide both distribution and transmission, as your 5 company does? Is that the norm? 6 MR. TAYLOR: Well, certainly, there are four 7 utilities in Alberta that provide both distribution and 8 transmission: ourselves; ATCO Electric; City of 9 Edmonton; City of Calgary. 10 Actually there's two smaller ones that have a 11 modest amount of transmission and those would be the 12 City of Lethbridge and the City of Red Deer. That's 13 actually another difference between Alberta and Ontario. 14 I understand in Ontario all the transmission is provided 15 by OHNC. That's not the case in Alberta. There are six 16 utilities that have transmission in Alberta. 17 MR. ROGERS: Just generally speaking, would 18 most of Alberta's residents be served by a distribution 19 company that had the same owner as the transmission 20 company, that served that distribution company? 21 MR. TAYLOR: That's difficult to generalize. 22 If I use the City of Calgary as an example, there are -- 23 the City of Calgary does have some of their own 24 transmission, but they also take some transmission 25 service from TransAlta. It's not one or the other. 26 As you probably know, in our new structure, 27 the costs of transmission service, regardless of who the 28 transmission facility owner is, are pooled and collected Les Services StenoTran Services Inc. 613-521-0703 2754 TRANSALTA PANEL 1, cr-ex (Rogers) 1 and charged by the transmission administrator. 2 I find it difficult to answer that directly. 3 MR. ROGERS: All right. Very well. Tell me, 4 how many end use customers in Alberta would be directly 5 connected to a transmission system? 6 MR. TAYLOR: Can you tell me what you mean by 7 a transmission system? 8 MR. ROGERS: Well, I guess everything over 25 9 kV. Isn't that your definition? 10 MR. TAYLOR: Directly connected? 11 MR. ROGERS: Yes. 12 MR. TAYLOR: So another difference is that 13 even if customers are directly connected to the 14 transmission system, they are still considered to be 15 customers of the LDC in whose service area they are 16 located, so they do not deal directly with the 17 transmission administrator. 18 For example, we have some large industrial 19 customers in our service area and all we really own as a 20 disco is the meter and we do the billing, but they are 21 still our customers and they are not direct customers of 22 the transmission administrator. 23 MR. ROGERS: Thank you. 24 --- Pause 25 MR. ROGERS: Mr. Taylor, help us with the new 26 pricing scheme in Alberta. I want to discuss with you 27 how it works, how it relates to what you are proposing 28 as your recommendation for this Board for my client. Les Services StenoTran Services Inc. 613-521-0703 2755 TRANSALTA PANEL 1, cr-ex (Rogers) 1 Before doing that, let me ask you: Was your company 2 involved in the stakeholdering process conducted by my 3 company or my client, rather? 4 MR. TAYLOR: TransAlta was involved. Yes. 5 MR. ROGERS: They were. And did you make 6 these proposals that you had made before this Board to 7 the stakeholdering process? 8 MR. TAYLOR: I don't believe they were 9 presented at that time. No. I don't think they were. 10 MR. ROGERS: Why weren't they? 11 MR. HODGKINSON: I think it's fair to say that 12 during that stakeholdering process, we looked at that as 13 a review of alternatives that were constantly evolving. 14 We hadn't evolved this alternative to that point at that 15 time. 16 MR. ROGERS: I see. I guess you can't blame 17 my client for not taking it into account when you hadn't 18 thought of it yet. 19 MR. HODGKINSON: I'm not blaming your client 20 for anything, sir. 21 MR. ROGERS: That's nice to hear. Thank you. 22 Let's talk about this Alberta scheme, Mr. 23 Taylor, if we could. You said, I think, about 35 per 24 cent of the revenue requirement is collected from all 25 transmission customers under the NPC method. That's 26 non-coincident peak. 27 MR. TAYLOR: That's correct, but just to be 28 clear, this is under the rates that will come into Les Services StenoTran Services Inc. 613-521-0703 2756 TRANSALTA PANEL 1, cr-ex (Rogers) 1 effect later on this spring as a result of the recent 2 Alberta Board's decision. 3 MR. ROGERS: Right. 4 MR. TAYLOR: In that decision, a portion of a 5 load customer's bill is collected based on that 6 customer's NCP and a portion of that customer's bill is 7 collected on the basis of on-peak energy. 8 MR. ROGERS: So 65 per cent is collected 9 through the energy component which is based on -- 10 MR. TAYLOR: Let me be clear. 11 MR. ROGERS: All right. 12 MR. TAYLOR: The 35 per cent is 35 per cent of 13 the revenue requirement, of the transmission 14 administrator's revenue requirement, is collected 15 through the demand charge, the NCP charges to loads. 16 MR. ROGERS: Yes. How do you collect the 17 other 65 per cent? 18 MR. TAYLOR: All right. In the Board's 19 decision, approximately 50 per cent of the revenue 20 requirement will now be collected from generators. We 21 have gone away from the model where it separated 22 connection costs. All the costs are connected from 23 loads -- 24 MR. ROGERS: I see. 25 MR. TAYLOR: -- to a different model where 50 26 per cent of the costs are collected from generators and 27 then presumably through the pool price eventually are 28 paid by loads in the form of a higher energy charge in Les Services StenoTran Services Inc. 613-521-0703 2757 TRANSALTA PANEL 1, cr-ex (Rogers) 1 the commodity market. 2 MR. ROGERS: Now, the peak period that you 3 told us about in Alberta that will be used, is that from 4 8:00 a.m. to 9:00 p.m. on weekdays? 5 MR. TAYLOR: 8:00 a.m. to 9:00 p.m. weekdays, 6 yes. That is also the current period. There is no 7 change in that. 8 MR. ROGERS: All right. Thank you. 9 MR. TAYLOR: Excluding statutory holidays, 10 just to be complete. 11 MR. ROGERS: Now, sir, just confirm this for 12 me, would you please, that the non-coincident peak 13 method and the associated ratchets or building demand 14 provisions or notice periods that you told us about. 15 They apply to all transmission customers and not just 16 those that may be using connection facilities, as my 17 client is proposing? 18 MR. TAYLOR: I'm sorry, I lost you a little 19 bit. You said they applied to all -- 20 MR. ROGERS: The non-coincident peak method 21 that you told us about and the associated ratchet or 22 billing demand provisions and the notice period 23 provisions, do they apply to all transmission customers? 24 MR. TAYLOR: They apply to all load customers 25 taking firm service. Another difference -- I didn't do 26 this in direct, but another difference in Alberta is we 27 do have what we call opportunity service or non-firm 28 service. Those are treated differently. Les Services StenoTran Services Inc. 613-521-0703 2758 TRANSALTA PANEL 1, cr-ex (Rogers) 1 For firm service, that's correct. All 2 transmission customers taking firm service pay an NCP 3 demand charge and a non-peak energy charge. 4 MR. ROGERS: Can you help me. How many 5 megawatts would take opportunity service as a percentage 6 of the total, approximately? 7 MR. TAYLOR: It would take me a little while 8 to figure that out, but it's quite small. It would be 9 under 10 per cent. 10 MR. ROGERS: Thank you. That's close enough, 11 I think. 12 Now, you mentioned a notice period. What is a 13 typical notice period in Alberta? 14 MR. TAYLOR: The notice period that the 15 transmission administrator has proposed as a result of 16 this recent Board decision is four years notice for load 17 reductions of up to ten megawatts and five years notice 18 for load reductions in excess of ten megawatts. 19 MR. ROGERS: And these types of provisions, 20 the notice, for example, is an attempt to mitigate 21 against the cost of -- I'm sorry -- to mitigate against 22 the risk of cost reassignment with respect to embedded 23 generation. 24 MR. TAYLOR: Not just with respect to embedded 25 generation. That's the point I was trying to make in 26 direct. This is an attempt to balance the interests of 27 customers whose load is leaving the system and the 28 interest of customers remaining on the system. Les Services StenoTran Services Inc. 613-521-0703 2759 TRANSALTA PANEL 1, cr-ex (Rogers) 1 For the load could be leaving the system for 2 any reason, even DSM, but it is, that's right, it's an 3 attempt to find an appropriate balance between the 4 impact on the customer that's leaving and the impact on 5 the customers that are remaining. 6 MR. ROGERS: I understand. I should have 7 added or reduced load. Your point is that for whatever 8 reason the load is reduced, those customers still have 9 an obligation to help pay for some of the costs that 10 were incurred to serve them. 11 MR. TAYLOR: That's right. 12 MR. ROGERS: Right. So these provisions do 13 what my client has attempted to do through this modified 14 gross load or net load billing. 15 MR. TAYLOR: That's right. As I said in my 16 direct, the concern I had with gross load billing, other 17 than the level, you know, what is a reasonable payment 18 required, is that gross load billing, while it collects 19 some costs from customers that leave the system due to 20 the installation of on-site generation does not catch 21 load leaving for any other reason. 22 MR. ROGERS: All right. Thank you. 23 --- Pause 24 MR. ROGERS: Help me with this, if you would, 25 Mr. Taylor. 26 I want to talk about how the LDCs operate in 27 Alberta. 28 MR. TAYLOR: Yes. Les Services StenoTran Services Inc. 613-521-0703 2760 TRANSALTA PANEL 1, cr-ex (Rogers) 1 MR. ROGERS: How the transmission costs are 2 transferred through to the ultimate end user. 3 Now, a significant portion of the demand in 4 Alberta is supplied to the end users that are customers 5 of LDCs. I think you told me that. In fact, I guess 6 all of them are, really, the way it operates because 7 there are no direct customers that deal directly with 8 the transmission company. 9 MR. TAYLOR: That's correct. 10 MR. ROGERS: So that essentially a 100 per 11 cent of the load in Alberta is supplied by the local 12 distribution company network. 13 MR. TAYLOR: That would be fair. 14 MR. ROGERS: And these customers pay their 15 transmission charges through rates set by the local 16 distribution utility. 17 MR. TAYLOR: Yes. I should clarify that for 18 ourselves and for ATCO those rates are approved by the 19 Alberta Energy Utilities Board. Unlike Ontario, though, 20 munies can set their own rates. 21 MR. ROGERS: I see. Well, what I want to get 22 to is how the transmission-related costs charged by the 23 transmission company to the distribution company are 24 translated into the distribution rates. 25 MR. TAYLOR: Right. 26 MR. ROGERS: Well, tell me how that is done. 27 MR. TAYLOR: Well, I can certainly speak for 28 how it's done in TransAlta. Les Services StenoTran Services Inc. 613-521-0703 2761 TRANSALTA PANEL 1, cr-ex (Rogers) 1 As we would in any cost of service study we, 2 as an LDC, look at the charges we are incurring from the 3 transmission administrator and, as you will recall, 4 those charges come at us in the form of on-peak energy 5 charges and NCP charges. Then what we do -- well, first 6 of all, if we do have customers connected directly to 7 the transmission system, those charges are flowed 8 through dollar-for-dollar to those direct customers with 9 a small adder for some administration and metering. 10 For all other customers, we allocate those 11 costs across rate classes based on the rate classes 12 contribution to on-peak energy or to our NCP demand. 13 MR. ROGERS: Then those rates or those costs 14 that imposed by the transmission system are then 15 recovered through a combination of fixed charges and 16 non-coincident peak demand. Is that right? 17 MR. TAYLOR: No, that's too simplistic. 18 We allocate the costs that we incur from the 19 transition administrator using on-peak energy and NCP 20 demand as the allocators but, for example, for 21 residential customers we have probably the same rate 22 structure that you do. We have a monthly fixed charge 23 and an energy charge. There is no on-peak/off-peak, 24 there is no demand charge, so when you get down to the 25 individual customer rates we have the kind of 26 traditional rates that all utilities have. 27 MR. ROGERS: Thank you. 28 --- Pause Les Services StenoTran Services Inc. 613-521-0703 2762 TRANSALTA PANEL 1, cr-ex (Rogers) 1 MR. ROGERS: Thank you very much. That has 2 been helpful for our understanding of how it works in 3 your products. 4 I'm a little bit unclear as what it is you are 5 recommending for this Board, though, in this case and 6 maybe you can help me out. 7 I understand that you are recommending that 8 this Board require that we have net load billing for end 9 use customers, but gross load billing at the municipal 10 level. Right? 11 MR. TAYLOR: At the LDC level, yes. 12 MR. ROGERS: At the LDC level. But that this 13 should be coupled with some type of notice provision to 14 protect against sunk costs. Is that right? 15 MR. TAYLOR: For a portion of the total 16 revenue requirement, yes. 17 MR. ROGERS: Tell us, if you can, in a little 18 more detail how that will work. What notice period 19 should be imposed? 20 MR. TAYLOR: Well, I didn't want to be so 21 presumptuous as to presume that what we have done in 22 Alberta would exactly match the Ontario situation, but I 23 think where we have landed in Alberta on that issue, as 24 I have mentioned, is approximately 35 per cent of the 25 revenue requirement will be collected through the demand 26 charge and its associated ratchets and minimums. I 27 think -- and we supported that as a reasonable balance 28 between the interests of the customer whose load is Les Services StenoTran Services Inc. 613-521-0703 2763 TRANSALTA PANEL 1, cr-ex (Rogers) 1 leaving the system and the interests of the remaining 2 customers. 3 Now, I know this is total coincidence, but 4 when I looked at the ratio of the revenue requirement 5 associated with the two connection pools in OHNC's 6 evidence, compared to the total revenue requirement, it 7 is also about 40 per cent. I accept that as just pure 8 coincidence, but given that I believe the balance we 9 struck in Alberta is reasonable I think a reasonable 10 balance in Ontario would be to apply ratchets, minimums, 11 some combination thereof, to the connection charges. 12 I believe five years is -- more than five 13 years would be unreasonably harsh to customers leaving 14 the system. I believe there should be some ratchets 15 and/or minimums applied to the connection facilities, 16 but no minimums or ratchets applied to the network 17 facilities. 18 MR. ROGERS: Am I not right that in Alberta 19 all transmission customers pay on a non-coincident peak 20 method? 21 MR. TAYLOR: In firm service, as we discussed 22 before -- 23 MR. ROGERS: For firm service, right. 24 But here it should only apply to connection 25 customers? 26 MR. TAYLOR: Not connection customers. Let me 27 back up. 28 So I am assuming here that the costs that are Les Services StenoTran Services Inc. 613-521-0703 2764 TRANSALTA PANEL 1, cr-ex (Rogers) 1 in the two connection pools will be recovered through 2 some sort of non-coincident peak demand charge. What I 3 was suggesting was that I believe a reasonable balance 4 between the interests of the customers we have been 5 discussing here would be to attach ratchets and minimums 6 to the costs recovered for line connection and 7 transformation connection. 8 I also said I think going more than five years 9 is too long and whether you use ratchets or minimums or 10 some combination of, I haven't specifically considered 11 for Ontario, but I don't think that you need to also 12 attach ratchets and minimums to the network pool, the 13 costs you are collecting for -- 14 MR. ROGERS: I understand. 15 So if we can summarize your position then, it 16 is that you agree with those proponents of gross load 17 billing to the extent that there is a concern about 18 protecting remaining customers for the sunk costs of the 19 transmission system as a matter of principle. 20 MR. TAYLOR: Well, as I said in my direct, I 21 think that customers leaving the system for any reason 22 should provide reasonable notice or equivalent payment 23 to achieve this balance. 24 MR. ROGERS: Right. So you are not in favour 25 of just a pure net billing system without any 26 impediments to abandoning load? 27 MR. TAYLOR: If by "pure net" means you can 28 leave the system tomorrow at no cost and no penalty -- Les Services StenoTran Services Inc. 613-521-0703 2765 TRANSALTA PANEL 1, cr-ex (Rogers) 1 MR. ROGERS: Right. 2 MR. TAYLOR: -- I think that is tilting the 3 pendulum too far the other way. 4 MR. ROGERS: The other way. And you agree -- 5 MR. TAYLOR: For the connection facilities. 6 MR. ROGERS: Yes, I understand. 7 MR. TAYLOR: Yes. 8 MR. ROGERS: But you agree that what we are 9 trying to do here is to find a balance between those two 10 extremes? 11 MR. TAYLOR: I agree we are trying to find a 12 balance and I just point out that I think that the same 13 balance would apply to load leaving the system for other 14 reasons as well. 15 MR. ROGERS: Yes, I understand your point. 16 All right, sir, thank you. 17 Those are the questions that I had. Thank you 18 very much. 19 Thank you, sir. 20 THE PRESIDING MEMBER: Okay. Thank you. 21 Mr. Vlahos. 22 MEMBER VLAHOS: Gentlemen, just a couple of 23 areas. 24 Mr. Taylor, you talked about the new 25 generation is not regulated generation. Can you just 26 expand? Explain what that means, "is not regulated 27 generation"? 28 MR. TAYLOR: Yes. In Alberta, the Electric Les Services StenoTran Services Inc. 613-521-0703 2766 TRANSALTA PANEL 1 1 Utilities Act, which was passed in 1995 and went into 2 force on January 1, 1996, essentially grandfathered all 3 the existing regulated generation. In that Act it was 4 declared on a go-forward basis any new generation would 5 be unregulated, would sell into a power pool which was 6 also set up in this Act, and it was only the existing -- 7 generation which was existing as of December 31, 1995 8 which continued to be regulated. 9 MEMBER VLAHOS: All right. So the pool, the 10 power pool is made from generation, from new generation 11 after 1995. 12 MR. TAYLOR: Actually, it is even more 13 complicated than that. 14 What was put in place for the existing 15 regulated generation was a series of financial hedges. 16 The purpose of that was to -- and unlike some 17 jurisdictions we actually had what was perceived to be, 18 anyway, a stranded benefit problem. So the purpose of 19 putting these legislative financial hedges in place was 20 to, first of all, ensure that the owners of those units 21 could recover their costs, but secondly to -- well, 22 three things actually. 23 Secondly, to flow through to end use customers 24 that value or the benefit that was seen in those units 25 being below market. 26 Thirdly, to put in place a structure that 27 would address concerns regarding market power. 28 So there was a complicated series of financial Les Services StenoTran Services Inc. 613-521-0703 2767 TRANSALTA PANEL 1 1 hedges put in place. This was put in place partly to, I 2 guess almost an -- I want to say an alternative 3 divestiture to achieve some of these concerns. 4 So one of the things that was specifically in 5 the Act was that there would be no forced divestiture. 6 So this was a way of capturing the benefits of the 7 exiting plans for the customers and addressing market 8 power concerns at the same time. 9 MEMBER VLAHOS: So the old generation, if I 10 can call it that, are the regulated generation that is 11 owned by the companies like your own or they may be 12 independent generators that deal with the utility and 13 those, of course, will be flowed through, you know, 14 whether it is cost of service regulation or 15 performance-based regulation, they will be flowed 16 through to the customers. Is that how it works? 17 MR. TAYLOR: Are you thinking of NUG-type 18 contracts? 19 MEMBER VLAHOS: No, I was thinking of the old 20 generation that would be owned by TransAlta Utilities -- 21 MR. TAYLOR: Yes. 22 MEMBER VLAHOS: -- or would be owned by 23 company "X" that would be supplying TransAlta Utilities. 24 MR. TAYLOR: Well, with the exception of the 25 few relatively small contracts with small power 26 producers that were entered into under an incentive 27 arrangement, TransAlta owns all its own generation. 28 MEMBER VLAHOS: All right. Thank you. Les Services StenoTran Services Inc. 613-521-0703 2768 TRANSALTA PANEL 1 1 So in addition to the old regulator generation 2 you have the power pool and now you also have a 3 transmission administrator. 4 MR. TAYLOR: That's correct. 5 MEMBER VLAHOS: Which we don't have in 6 Ontario. 7 --- Pause 8 MR. TAYLOR: I think that's fair. 9 I think one of the reasons that we have this 10 additional entity called the transmission administrator 11 is that in Alberta we have several transmission owners 12 and we needed a mechanism to pool and average the 13 transmission costs. One of the objectives, explicit 14 objectives in our Act is postage stamp pricing for 15 transmission service across the province. 16 So unlike the case here, where I understand 17 OHNC does own all the transmission, we needed a 18 mechanism to pool, if you will, or average the 19 transmission costs and this was one of the results of 20 that. 21 MEMBER VLAHOS: So OHNC, the transmission 22 company, it is in essence the transmission 23 administrator. 24 MR. TAYLOR: I think that would be fair, yes. 25 MEMBER VLAHOS: Okay. 26 Now, were you surprised with the kinds of 27 questions you have been receiving about what is 28 governing Alberta in terms of the basic infrastructure? Les Services StenoTran Services Inc. 613-521-0703 2769 TRANSALTA PANEL 1 1 Are you surprised at all? 2 MR. TAYLOR: Well, I have been monitoring the 3 hearing and I have been surprised how often Alberta has 4 come up, yes. 5 MEMBER VLAHOS: Are you surprised with the 6 general -- the exhibited lack of knowledge, including my 7 own, about the Alberta system? 8 MR. TAYLOR: That's a dangerous question. 9 --- Laughter 10 MR. TAYLOR: No. 11 MEMBER VLAHOS: You are not surprised? 12 MR. TAYLOR: I'm not surprised, no. 13 MEMBER VLAHOS: You don't think that there is 14 enough on the record for someone to get into the details 15 as to what is happening in Alberta other than the 16 decisions that we have at two excerpts we have from the 17 decision? 18 MR. TAYLOR: I think it is fair to say that 19 the structure that we have put in place in Alberta is 20 quite complicated and difficult for someone who is not 21 immersed in the Alberta situation to fully understand 22 all the intricacies. That is why I took some time in my 23 opening to try to clarify some of the things that I 24 thought were relevant for this proceeding. 25 MEMBER VLAHOS: I read those with interest, 26 sir, but is it a primer that you can suggest to the 27 Board -- 28 MR. TAYLOR: A primer? Les Services StenoTran Services Inc. 613-521-0703 2770 TRANSALTA PANEL 1 1 MEMBER VLAHOS: -- that it will sort of a 2 neutral person, nothing that has to be developed, but 3 something that sort of explains, maybe a government 4 document that explains as to -- 5 MR. TAYLOR: Well, if you are just talking 6 about the structure of the industry in general and not 7 the intricacies of rate design, there are several 8 documents on the Web site for the Alberta government's 9 Department of Resource Development, which is the 10 department that includes their electricity branch, and I 11 would highly commend those to you. They are well done 12 and unbiased. 13 MEMBER VLAHOS: All right. Thank you. 14 Mr. Hodgkinson, your answer to one of the 15 questions was that -- well, it doesn't matter whether 16 one looks at the OHNC proposal or the OPG proposal in 17 terms of net present value, they are the same. 18 Now, maybe it was Mr. Taylor, forgive me. I 19 believe it was Mr. Taylor. 20 MR. TAYLOR: That's correct. 21 MEMBER VLAHOS: Okay, I'm sorry. 22 I guess I have a bit of difficulty. You 23 probably have seen that in one of the responses to 24 interrogatories. Is this you are referring to? 25 MR. TAYLOR: Yes, I was going from memory here 26 and I did read through all their interrogatory responses 27 and I probably should said "subject to check". 28 But my recollection was that if you assume a Les Services StenoTran Services Inc. 613-521-0703 2771 TRANSALTA PANEL 1 1 50 per cent payment forever, at least a long period of 2 time, compare that to 100 per cent payment declining to 3 zero over 10 years, depending on what time frame you 4 assume you will get a present value of roughly the 5 same -- net present value cost to the customer. 6 MEMBER VLAHOS: That's what I wanted to you 7 talk with you about, whether the assumption was that the 8 50 per cent would apply forever. 9 MR. TAYLOR: I don't know. I would have to 10 check. 11 You could work backwards and see how many 12 years you needed to make it work out to zero, but I 13 don't know. 14 MEMBER VLAHOS: Okay. But do you gentlemen 15 understand the difference in terms of the date certain 16 of one proposal versus another? The OPG has an end date 17 of 10 years, the OHNC proposal does have a 18 recommendation to start off with, but in due course 19 there will be individual arrangements with specific 20 customers. Are you aware of that? 21 MR. TAYLOR: Yes. My understanding is that 22 the OPGI proposal is a 10-year phase from 100 per cent 23 to zero per cent starting at the completion of each 24 project. So it is not 10 years starting today for 25 everybody, it is 10 years from the start of each 26 project. 27 I listened with interest to OHNC describe 28 their current thinking on contracts, and I guess the Les Services StenoTran Services Inc. 613-521-0703 2772 TRANSALTA PANEL 1 1 difficulty I have with that is that it doesn't help us 2 with our concerns for certainty that we have discussed. 3 I might also add that it reminded me of 4 another thing that has worked well in Alberta, that our 5 contracts are actually very simple. 6 The contracts basically have some blanks for 7 the customer name, customer location, the contract 8 demand and the contribution, if any. They are not an 9 opportunity to negotiate special terms, special rates. 10 It is just setting out on paper, so there is no 11 ambiguity, how the tariff approved by the regulator will 12 be implemented. 13 So I'm not sure I understand what OHNC has in 14 mind in terms of negotiating or developing contracts 15 here, because I was certainly thinking that the contract 16 was much simpler than that, it was simply putting down 17 on paper how the approved tariff will be implemented. 18 So it doesn't provide, certainly me, with any 19 comfort as to how the world will evolve. 20 MEMBER VLAHOS: Mr. Hodgkinson, you did talk 21 about a regulatory risk quite a bit in your initial 22 testimony. Do you have anything to add to this as to 23 what would be the risks that you see if variables are 24 not known and measurable from now, based on this 25 decision as opposed to leaving things in the future. 26 Do you have any comment? 27 MR. HODGKINSON: I think the only comment I 28 would make is that through discussion we have had with a Les Services StenoTran Services Inc. 613-521-0703 2773 TRANSALTA PANEL 1 1 number of industrial customers, they are very reluctant 2 to make long term commitments without having some 3 comfort that the rules aren't going to continually 4 change and evolve. As a result, I think the lack of 5 clarity will likely slow down in this sector. 6 MEMBER VLAHOS: Lastly, gentlemen, and I 7 believe it was you, Mr. Taylor, you talked about an 8 impact in a typical 100 megawatt cogen plant that gross 9 billing will have and you mentioned the amount of $1.5 10 million per year. Do you recall that? 11 MR. TAYLOR: Yes. 12 MEMBER VLAHOS: I was just wondering, what 13 would be the natural gas intake for a 100 megawatt plant 14 in BCF? 15 MR. HODGKINSON: I don't have the numbers at 16 the tip of my tongue. We can get them for you because 17 we have a 110 megawatt plant in the Toronto area. 18 MEMBER VLAHOS: All right. I will take 110. 19 MR. HODGKINSON: I can get those for you, but 20 I don't have them with me. 21 MEMBER VLAHOS: Those are not confidential, 22 are they? Are you referring that to a specific project 23 of yours? 24 MR. HODGKINSON: I can get you in BCF the gas 25 consumption of the 100 megawatt facilities. 26 MEMBER VLAHOS: I'm just looking for something 27 that is typical, not necessarily your own plant. What 28 would be a typical gas intake for a 100 megawatt plant? Les Services StenoTran Services Inc. 613-521-0703 2774 TRANSALTA PANEL 1 1 MR. HODGKINSON: As I said, I will undertake 2 to get that for you. 3 MEMBER VLAHOS: Perhaps, Mr. Lyle. 4 MR. LYLE: Yes. Make that Undertaking F14.2. 5 UNDERTAKING NO. F14.2: Mr. Hodgkinson 6 undertakes to advise typical gas intake 7 for a 100 megawatt plant 8 MEMBER VLAHOS: Okay. Thank you, gentlemen. 9 Those are my questions. 10 THE PRESIDING MEMBER: Thank you. Mr. Smith. 11 MEMBER SMITH: Continuing in the ignorant 12 about Alberta category, the more general, showing a real 13 level of ignorance. At the customer level, does the 14 customer now get a bill that shows all the different 15 components that you have been talking about? 16 MR. TAYLOR: In TransAlta's service area, the 17 customer bill is now unbundled to the extent that the 18 commodity, the generation piece is shown separately and 19 the bundled delivery charge though, the transmission and 20 distribution together, is shown separately. 21 We have gone so far as to unbundle the energy 22 from the delivery. 23 MEMBER SMITH: So there's two components 24 there. 25 MR. TAYLOR: Two components, and each of 26 those, depending on the rate can have, you know, an 27 energy charge and a demand charge. The rate can look 28 quite complicated now, but it's generally into two broad Les Services StenoTran Services Inc. 613-521-0703 2775 TRANSALTA PANEL 1 1 components. 2 MEMBER SMITH: Since the combination of 3 deregulation and reregulation began in Alberta some 4 years ago, what has been the trend in electricity 5 prices, in commodity prices and in transmission prices? 6 Have they gone down, stayed the same, gone up? 7 MR. TAYLOR: Well, overall customer rates have 8 gone down continuously in Alberta since the early 9 nineties. That's partly as a result of surplus 10 generation capacity on the system being absorbed by the 11 continued growth and load. 12 More recently, with the tightening of the 13 market, the spot price of energy in Alberta or the pool 14 price has jumped significantly over the last two or 15 three years, but the way our financial hedges work is 16 that in that these customers are only actually exposed 17 to that spot price to the extent that they are not 18 covered by hedges from existing regulated generators, so 19 the average energy cost has continued to fall over that 20 period, but an opportunity customer, I think you would 21 call him a surplus customer who is just buying from the 22 pool, has seen significant increases in the commodity 23 charge as our system has tightened. 24 Transmission costs have generally fallen. 25 There have not been significant transmission capacity 26 additions required over the last few years. Again, 27 natural depreciation plus low growth has resulted in a 28 generally downward trend in transmission tariffs, but it Les Services StenoTran Services Inc. 613-521-0703 2776 TRANSALTA PANEL 1 1 hasn't been earth shattering. It has been relatively 2 flat. 3 MEMBER SMITH: One final question. The 4 amounts of export and wheeling in Alberta, has the new 5 regime had a big impact on that? 6 MR. TAYLOR: Not the regime per se. The 7 tightness of our market in Alberta has certainly had a 8 big impact. We used to be an exporter and we had 9 surplus. We are a tremendous importer on average right 10 now, but that's more because of the supply demand. 11 We have gone from what we used to call a tight 12 power pool to now this open power pool, so there should 13 have been some changes in that, but I wouldn't attribute 14 the significant change in the proposal or the tie even 15 significantly to the change in structures and primarily 16 driven by the change in the supply demand balance in 17 Alberta. 18 MEMBER SMITH: Thank you. 19 THE PRESIDING MEMBER: Those are the Board's 20 questions. 21 Thank you very much. 22 MR. ROGERS: I'm sorry, Dr. Higgin, just 23 before the witnesses leave, there's one matter I meant 24 to ask, an undertaking really. I wonder if I could just 25 put it to them now. 26 THE PRESIDING MEMBER: Yes. 27 CROSS-EXAMINATION 28 MR. ROGERS: Gentlemen, you commented -- I Les Services StenoTran Services Inc. 613-521-0703 2777 TRANSALTA PANEL 1, cr-ex (Rogers) 1 think it was you, Mr. Taylor, about the liability clause 2 proposed by my client. 3 MR. TAYLOR: Yes. 4 MR. ROGERS: Would you be kind enough to file 5 by way of undertaking the comparable clause that's in 6 your tariff. 7 MR. TAYLOR: Yes, I would. 8 MR. LYLE: We will make that Undertaking 9 No. F14.3. 10 UNDERTAKING NO. F14.3: Undertaking by 11 Mr. Taylor to File Comparable Liability 12 Clause to that of OHNC 13 THE PRESIDING MEMBER: Mr. Budd. 14 MR. BUDD: Thank you, sir. I have no 15 questions in redirect. 16 THE PRESIDING MEMBER: Okay. Thank you, 17 gentlemen. 18 Thank you very much for your testimony. 19 MR. TAYLOR: Thank you. 20 THE PRESIDING MEMBER: That is now lunch time. 21 We will come back at two. My colleague said "Two". So 22 we will have two o'clock and we will then see Mr. 23 Gibbons and Pollution Probe. 24 Thank you. 25 --- Upon recessing at 1259 26 --- Upon resuming at 1406 27 THE PRESIDING MEMBER: Please be seated. 28 Good afternoon, everybody. The document that Les Services StenoTran Services Inc. 613-521-0703 2778 TRANSALTA PANEL 1, cr-ex (Rogers) 1 you filed this morning, Mr. Rogers. Do you know where 2 it is? 3 MR. THIESSEN: We have it here. 4 THE PRESIDING MEMBER: The Board would rather 5 have a chance to look at that. 6 MR. ROGERS: Oh, yes. The staff have had it 7 since this morning. 8 MR. LYLE: We will make it Exhibit G14.3. 9 THE PRESIDING MEMBER: It will be 14.3, I 10 think. 11 MR. CAMPBELL: What was the number? 12 THE PRESIDING MEMBER: 14.3, I think. 13 EXHIBIT NO. G14.3: Document entitled 14 "Implementation of Transmission Rates" 15 MR. ROGERS: I hope that addresses the Board's 16 concern. 17 There is one correction I would like to make 18 in another document that I filed this morning and I 19 apologize. In fact, I think it was filed on Friday. 20 It's Exhibit G13.1, which is the explanation of OHNC's 21 proposal re WT transactions. I apologize. 22 In the haste to get this back to you, prepared 23 and filed, there is one error. The word -- it's on the 24 first page. I wonder if I could just have it 25 distributed as just a fresh exhibit that clarifies it. 26 If that's what the Board has just been provided with, 27 you will see on the first page, about half way down the 28 page, in the right hand column, there's a mark. Les Services StenoTran Services Inc. 613-521-0703 2779 TRANSALTA PANEL 1, cr-ex (Rogers) 1 The word "lower" has been substituted for 2 "higher" which obviously makes a difference. I 3 apologize for that. 4 THE PRESIDING MEMBER: Okay. 5 MR. ROGERS: This is now correct. We have 6 done it this way so that everyone can see where the 7 correction has been made. 8 THE PRESIDING MEMBER: Good. Certainly my 9 colleague had noted that there was a problem there. 10 MR. ROGERS: That's right. 11 THE PRESIDING MEMBER: All right. 12 Are there any more preliminary matters from 13 anybody? No. 14 Okay. Mr. Klippenstein. 15 MR. KLIPPENSTEIN: Thank you, Mr. Chairman. I 16 would like to call Jack Gibbons on behalf of Pollution 17 Probe and I wonder if he could be sworn. 18 SWORN: JACK GIBBONS 19 MR. KLIPPENSTEIN: I have previously provided 20 copies of Mr. Gibbons' CV and I believe they are 21 available and just require an exhibit number. 22 MR. LYLE: We will make that Exhibit G14.4. 23 MR. KLIPPENSTEIN: Thank you. 24 EXHIBIT NO. G14.4: Curriculum Vitae of 25 Jack Gibbons, Pollution Probe 26 EXAMINATION-IN-CHIEF 27 MR. KLIPPENSTEIN: Mr. Gibbons, I would note 28 that you are presently the Senior Economic Adviser for Les Services StenoTran Services Inc. 613-521-0703 2780 POLLUTION PROBE PANEL 1, in-ch (Klippenstein) 1 the Canadian Institute for Environmental Law and Policy. 2 Is that correct? 3 MR. GIBBONS: That's correct. 4 MR. KLIPPENSTEIN: And you are the Chair of 5 the Ontario Clean Air Alliance. Is that right? 6 MR. GIBBONS: Yes. 7 MR. KLIPPENSTEIN: You are a former 8 Commissioner of Toronto Hydro. 9 MR. GIBBONS: Yes. 10 MR. KLIPPENSTEIN: And a former Ontario Energy 11 Board staff member. 12 MR. GIBBONS: Yes. 13 MR. KLIPPENSTEIN: I understand you are 14 presently a member of the Environment Subcommittee of 15 the Ontario Electricity Transitions Committee. Is that 16 right? 17 MR. GIBBONS: Yes. 18 MR. KLIPPENSTEIN: And you very recently 19 authored a report released by the Ontario Clean Air 20 Alliance called "Pollution Loopholes", which is an 21 assessment of the government's regulations for the 22 electricity sector. 23 MR. GIBBONS: Right. 24 MR. KLIPPENSTEIN: Mr. Gibbons, Pollution 25 Probe has previously filed in this preceding your report 26 entitled "Net Load Billing, Environmental Benefits and 27 Rate Impacts" which is found at Exhibit H, Tab 24, 28 Schedule 1, and has filed answers to the interrogatories Les Services StenoTran Services Inc. 613-521-0703 2781 POLLUTION PROBE PANEL 1, in-ch (Klippenstein) 1 delivered by various parts as answered by you. 2 Do you adopt and confirm the information in 3 these materials as your evidence and as accurate to the 4 best of your knowledge, information and belief? 5 MR. GIBBONS: I do. 6 MR. KLIPPENSTEIN: I wonder, Mr. Gibbons, if 7 you could very briefly summarize the most important 8 points in your evidence. 9 MR. GIBBONS: Yes. According to OHNC's AGRA 10 Monenco forecast, 1,950 megawatts of new embedded 11 generation will be built in Ontario between now and the 12 year 2008. 13 I have got in my evidence -- I have quantified 14 the emission reduction benefits which would flow from 15 1,950 megawatts of new gas fired generation, assuming 16 that it displaces on a 100 per cent basis OPG's fossil 17 generation, which is primarily coal fired generation. 18 Those emissions reduction benefits are very 19 significant. On page 5, Table 2 of my evidence, I have 20 presented those emissions reduction benefits as a 21 percentage of OPG's emissions in 1998. 22 For example, the emissions reduction benefits 23 in terms of greenhouse gas emissions are equivalent to 24 27 per cent of OPG's greenhouse gas emissions in 1998; 25 in terms of sulphur dioxide the number is 45 per cent; 26 in terms of nitrogen oxide the number is 28 per cent; 27 and in terms of mercury it is 43 per cent. So 1,950 28 megawatts of new gas-fired generation could provide very Les Services StenoTran Services Inc. 613-521-0703 2782 POLLUTION PROBE PANEL 1, in-ch (Klippenstein) 1 significant benefits in terms of reduced emissions which 2 will be beneficial in terms of public health and the 3 environment. 4 Also in their evidence Ontario Hydro gave a 5 forecast of what rates would be, aggregate transmission 6 rates would be, in nominal terms, going out to the year 7 2008 assuming 100 per cent net load billing for network 8 and connection charges, and IUCM, the Conference Board 9 of Canada's Consumer Price Index forecast to convert 10 those numbers into real dollars. Whereas, in nominal 11 terms, Ontario Hydro's forecast showed a slight increase 12 in transmission rates assuming 100 per cent net load 13 billing for network and connection charges, when you 14 convert it into real dollars we see that, actually, even 15 with net load billing, real rates will decline during 16 the period 2000 to 2008 and they will decline by 17 approximately 11 per cent in real terms. 18 MR. KLIPPENSTEIN: Just two questions. 19 Can you briefly provide your opinion on 20 whether or not OHNC's gross load billing proposal is in 21 the public interest? 22 MR. GIBBONS: I believe it is not in the 23 public interest. First of all, gross load billing is a 24 departure from the status quo rate design, which is net 25 load billing, which is user pay. Ontario Hydro's 26 proposal is proposing to move away from user pay, which 27 is the fundamental principle of public utility 28 regulation. Les Services StenoTran Services Inc. 613-521-0703 2783 POLLUTION PROBE PANEL 1, in-ch (Klippenstein) 1 Ontario Hydro's proposal will also discourage, 2 financially penalize, companies that build new natural 3 gas combined cycle power plants. Therefore, in my 4 opinion, this proposal is inconsistent with at least two 5 objectives of the Ontario Energy Board Act, one of which 6 is to promote competition and the other one is to 7 promote cleaner forms of electricity generation. 8 If net load billing was to -- if it was 9 reasonable to assume that net load billing were to lead 10 to significantly higher transmission rates in real 11 terms, then I think I would concede there could be a 12 good argument for gross load billing. But since that is 13 not the case, I don't think it is appropriate for the 14 OEB to use its power under the Ontario Energy Board Act 15 to set transmission rates in a way which would 16 discourage -- frustrate the movement towards cleaner 17 forms of generation and would frustrate the development 18 of a competitive electricity market in Ontario. 19 MR. KLIPPENSTEIN: Dr. Orans said, a few days 20 ago, that the total cost to society of coal-fired power 21 equals OPGs financial cost of producing it. That 22 appears at Volume 10 of the transcripts, page 1942, 23 lines 4 to 13. Would you agree that the total cost to 24 society of coal-fired power is the same as OPG's 25 financial cost of producing it? 26 MR. GIBBONS: Absolutely not. There are at 27 least -- there are more than 30 air pollutants that are 28 emitted by coal-fired power plants. At least 10 of them Les Services StenoTran Services Inc. 613-521-0703 2784 POLLUTION PROBE PANEL 1, in-ch (Klippenstein) 1 are very serious. These air pollutants impose costs on 2 society that are not borne by OPG. They impose health 3 costs, such as increased heart disease, increased lung 4 disease, more asthma attacks, more cancers and 5 ultimately more premature deaths. These are costs to 6 society in terms of public health and they do not show 7 up on OPG's financial books. So it is absolutely wrong 8 to suggest the total cost to society of producing 9 coal-fired electricity equals the financial cost that 10 accrues to Ontario Power Generation have operating their 11 coal-fired power plant. 12 MR. KLIPPENSTEIN: I have no further 13 questions, Mr. Chair. I would make Mr. Gibbons 14 available for cross-examination. 15 THE PRESIDING MEMBER: Mr. Fisher? 16 MR. FISHER: I have no questions, thank you, 17 Dr. Higgin. 18 THE PRESIDING MEMBER: Mr. Cowan? 19 CROSS-EXAMINATION 20 MR. COWAN: Mr. Gibbons, what factors would 21 you include in your sense of "in the public interest" 22 that you have just referred t? 23 MR. GIBBONS: In determining whether or not we 24 should move to net load billing? 25 MR. COWAN: Yes. 26 MR. GIBBONS: There are a number of factors. 27 As I mentioned a few minutes ago, one of the benefits of 28 moving to net load billing is cleaner generation, lower Les Services StenoTran Services Inc. 613-521-0703 2785 POLLUTION PROBE PANEL 1, cr-ex (Cowan) 1 emissions from power plants creating a more competitive 2 market which will hopefully lead to lower commodity 3 prices, a more competitive economy making Ontario 4 industrial firms more competitive. Those would be some 5 of the benefits. 6 MR. COWAN: In the past, on the net gross, I 7 have asked various witnesses whether they saw areas of 8 geographical difference. In a sense, I was asking: Do 9 your principles apply everywhere equally. Do your 10 principles apply everywhere equally? 11 MR. GIBBONS: Could you be a bit more 12 specific. Are you suggesting why they wouldn't? 13 MR. COWAN: Can you think of any areas in 14 Ontario where improved clean air would be a disservice? 15 MR. GIBBONS: No, sir. 16 MR. COWAN: Can you think of significant areas 17 in Ontario which would pay for cleaner air yet receive 18 no cleaner air as a result of net or gross load billing? 19 MR. GIBBONS: I think all areas of Ontario 20 would benefit. I suspect there are certain areas who 21 would benefit more than others. Ontario is a very large 22 province. 23 MR. COWAN: The numbers of people currently 24 suffering from asthma and emphysema that are somewhat 25 aggravated by air pollution that you would attribute to 26 coal generation, what numbers approximately are 27 involved. Do you know? 28 MR. GIBBONS: In terms of how many suffer? Les Services StenoTran Services Inc. 613-521-0703 2786 POLLUTION PROBE PANEL 1, cr-ex (Cowan) 1 Well, according to the Government of Ontario there are 2 1,800 premature deaths per year in Ontario as a result 3 of air pollution. Other people have suggested higher 4 numbers. In terms of asthma, you sometimes see quotes 5 in the paper that suggest that one-fifth of Ontario 6 children suffer from asthma. 7 MR. COWAN: In short, would you take the point 8 of view that this would be a financial relief that would 9 allow us to all breathe more easily? 10 MR. GIBBONS: Protecting public health would 11 certainly reduce our expenditures on the health care 12 system, yes. 13 MR. COWAN: That's all. Thank you kindly. 14 THE PRESIDING MEMBER: Thank you. 15 Mr. Campbell, please. 16 MR. CAMPBELL: Yes, Mr. Chairman. 17 CROSS-EXAMINATION 18 MR. CAMPBELL: Mr. Gibbons, at the bottom of 19 page 2, I guess about two-thirds of the way down, the 20 end of the first full paragraph of the introduction you 21 state that "generation will bypass, that is, not use, 22 OHNC's transmission network. That is new generation we 23 are talking about here? Do you see that? 24 MR. GIBBONS: Yes. 25 MR. CAMPBELL: Do you believe that statement 26 to be true? 27 MR. GIBBONS: Yes. I thought that was the 28 primary concern that OPG had about new embedded Les Services StenoTran Services Inc. 613-521-0703 2787 POLLUTION PROBE PANEL 1, cr-ex (Campbell) 1 generation under a net load billing proposal. 2 MR. CAMPBELL: Is it not correct that 3 customers installing embedded generation will continue 4 to use the network for backup or power quality support 5 and to sell any excess production that they have? 6 MR. GIBBONS: Absolutely. 7 MR. CAMPBELL: So you would agree, then, I 8 take it, that it is not correct to equate "bypass" to 9 "non-use" in your testimony? 10 MR. GIBBONS: No. It was a simplifying 11 statement, and, yes, they certainly continue to use the 12 transmission system. So I don't disagree with what you 13 are suggesting. 14 MR. CAMPBELL: All right. Now, as I 15 understand it, you are advocating net billing not only 16 for network but for connection charges as well? 17 MR. GIBBONS: Yes, sir. 18 MR. CAMPBELL: Again, I take it this is aimed 19 at the goal of encouraging new gas-fired generation 20 which you speak to at the bottom of page 2 as bringing 21 about a reduction, a dramatic reduction in emissions. 22 Is that correct? 23 MR. GIBBONS: Yes. 24 MR. CAMPBELL: And you would agree with me 25 that this reduction in emissions will only occur if new 26 gas-fired plant replaces existing plant? 27 MR. TAYLOR: Yes, sir. 28 MR. CAMPBELL: I take it you propose to Les Services StenoTran Services Inc. 613-521-0703 2788 POLLUTION PROBE PANEL 1, cr-ex (Campbell) 1 accomplish this in two ways. 2 First, you want to encourage new embedded 3 generation through net load billing. Correct? 4 MR. TAYLOR: Yes. 5 MR. CAMPBELL: Again, the purpose of this is 6 to displace OPG fossil generation? 7 MR. TAYLOR: Yes. 8 MR. CAMPBELL: Second, you wish to discourage 9 continued production from existing coal plants by 10 restricting export opportunities through high export 11 charges. Is that also correct? 12 MR. TAYLOR: That is not part of my testimony, 13 sir. 14 MR. CAMPBELL: I know it wasn't part of your 15 written testimony but, certainly, we concluded from the 16 questions that your counsel asked and the interrogatory 17 questions that were asked, with respect to net imports 18 and exports -- and whether it is part of your testimony 19 or not -- 20 MR. KLIPPENSTEIN: Mr. Chairman, I wonder if I 21 could just interrupt. 22 Mr. Gibbons has pointed out that the question 23 he is being asked, with respect to export, is not the 24 subject of his testimony and, as I understand it, the 25 role of cross-examination is to test the testimony that 26 the evidence is put forward and I just worry that if we 27 are going to get into topics that aren't even covered in 28 his evidence, we may be going astray. Les Services StenoTran Services Inc. 613-521-0703 2789 POLLUTION PROBE PANEL 1, cr-ex (Campbell) 1 THE PRESIDING MEMBER: Mr. Campbell, would you 2 like to respond to that? 3 MR. CAMPBELL: Yes, I would, Mr. Chairman. 4 We have been asked interrogatories, by 5 Pollution Probe, with respect to both imports and 6 exports. Certainly, Mr. Klippenstein's questions of our 7 panel, on cross-examination -- which definitely was 8 there to deal with export and wheel-through charges -- 9 raised questions in this area. Mr. Gibbons has appeared 10 as having a certain objective and I wondered whether -- 11 what his position is on matters that are directly at 12 issue in these proceedings and have been raised in his 13 interrogatories. 14 THE PRESIDING MEMBER: Okay. 15 MR. CAMPBELL: Certainly, Mr. Chairman, if 16 Mr. Klippenstein tells me that his client will not be 17 taking a position, at all, on export charges, then I can 18 move on. 19 But I certainly suspect that Pollution Probe 20 definitely intends to take a position on export charges. 21 THE PRESIDING MEMBER: Okay, my colleague 22 points out that Mr. Gibbons is, in fact, by virtue of 23 his CV, (off microphone) Canadian Institute for 24 Environmental Law and Policy. Okay? So that he is, in 25 that sense, independent, not directly part of Pollution 26 Probe, in that sense. So he is appearing as a 27 consultant, in his own right, and he is not appearing as 28 part of Canadian Institute for Environmental Law and Les Services StenoTran Services Inc. 613-521-0703 2790 POLLUTION PROBE PANEL 1, cr-ex (Campbell) 1 Policy. 2 So I guess the ceiling is that you don't have 3 the right to ask him questions about the environmental 4 aspects (off microphone) export wheeling charges; 5 however, you can ask him general questions about (off 6 microphone) as a party to this hearing, Mr. Gibbons has 7 been sitting in the back for several days and has heard 8 the exchanges. So that is where I think we are with the 9 ruling. 10 MR. CAMPBELL: Can I have just a moment, 11 Mr. Chairman? 12 --- Pause 13 MR. CAMPBELL: Mr. Gibbons, when you were 14 calculating your emissions figures that are set out in 15 Exhibit H24.1, did you segregate production from 16 Ontario's coal facilities that was used for export from 17 domestic production? 18 MR. TAYLOR: No. 19 MR. CAMPBELL: So this includes both domestic 20 and export production? 21 MR. TAYLOR: Yes, sir. 22 MR. CAMPBELL: And are you also suggesting in 23 your testimony, therefore, that that export production 24 has the same qualities and characteristics as the 25 domestic production? 26 MR. TAYLOR: I am certainly making no 27 distinction. But if the exports came from a marginal 28 plant, it might be on a -- it might have a higher Les Services StenoTran Services Inc. 613-521-0703 2791 POLLUTION PROBE PANEL 1, cr-ex (Campbell) 1 emissions. I mean I just don't know. 2 MR. CAMPBELL: And, similarly, when your 3 counsel referred to the document "Pollution Loopholes" 4 and he raised that document, is it not correct that that 5 entire document makes no distinction between the 6 emissions that are spoken of, in terms of whether those 7 emissions come from export-derived production or Ontario 8 load-derived production? 9 MR. TAYLOR: That is correct. 10 MR. CAMPBELL: Mr. Chairman, given those 11 answers, I don't see how I can deal with this witness' 12 testimony without being allowed to go into how the very 13 emissions that he has put in evidence and my friend 14 raised by referring to this other document -- how I can 15 test this witness' views on that issue in these 16 proceedings without being allowed to ask questions in 17 those areas. 18 THE PRESIDING MEMBER: Well -- 19 MR. KLIPPENSTEIN: Mr. Chairman, if I could 20 respond to that. 21 Mr. Gibbons has just said he doesn't deal with 22 exports separately and so, whatever questions 23 Mr. Campbell has about exports won't make any 24 difference -- it won't clarify anything in the witness' 25 testimony -- and the fact is that Mr. Gibbons' testimony 26 doesn't deal with export, at all. It is just not 27 relevant, as testimony. And whatever Mr. Campbell may 28 want to say about other parts of Pollution Probe's Les Services StenoTran Services Inc. 613-521-0703 2792 POLLUTION PROBE PANEL 1, cr-ex (Campbell) 1 position, which Pollution Probe may want to 2 cross-examine on and then raise in argument is a 3 perfectly legitimate procedure -- and, certainly, the 4 Board would not want people to submit evidence on 5 everything they intend to raise in argument. So the 6 distinction is very clear and nothing is gained by 7 talking about exports when the witness' testimony 8 doesn't do so, in my submission. 9 THE PRESIDING MEMBER: Well, Mr. Campbell, I 10 think that the feeling the Board has is that, basically, 11 you can proceed asking questions on (off microphone) 12 testimony here (off microphone) holistic approach to 13 emissions. There is no specific testimony that 14 Mr. Gibbons is willing or able -- I put those words (off 15 microphone) -- regarding exports as a subset. 16 MR. CAMPBELL: Mr. Gibbons, the thrust of your 17 testimony, as I understand it, is to eliminate, or 18 reduce to the maximum extent possible, coal-fired 19 emissions. Correct? 20 MR. TAYLOR: No, sir. The thrust of my 21 testimony is that if you build a 1950-megawatt gas-fired 22 generation, there could be very significant emissions 23 reduction as a result of displacing goal-fired power. 24 MR. CAMPBELL: What if the effect of your 25 proposal was to, in effect, go farther than that and 26 largely eliminate OPG's ability to generate from 27 coal-fired generation? 28 Would that, in your view, be a desirable Les Services StenoTran Services Inc. 613-521-0703 2793 POLLUTION PROBE PANEL 1, cr-ex (Campbell) 1 outcome? 2 MR. TAYLOR: Certainly, from a public health 3 point of view, yes. 4 MR. CAMPBELL: If OPG as a result had to shut 5 down, that would simply be a consequence that you would 6 find is quite acceptable in light of that public -- what 7 you see as that public health outcome. Correct? 8 MR. GIBBONS: From a public health point of 9 view, it would be positive. 10 MR. CAMPBELL: And you are expressing the view 11 that that would be, in your opinion, a positive outcome 12 overall? 13 MR. GIBBONS: Well, I don't think my testimony 14 dealt with that directly. 15 I think though, in my opinion, measures that 16 would lead to a very significant reduction in OPG's 17 coal-fired electricity in the order of about 83 per cent 18 over the time period 2002-2014. 19 The Ontario Clean Air Alliance did a study 20 which showed that that could be achieved at a very low 21 financial cost to electricity rate payers in Ontario. 22 So, yes, my opinion would be, if you pushed 23 me, that level of emissions reduction would overall be 24 in the public interest. 25 MR. CAMPBELL: Would the reduction beyond that 26 level also be in the public interest? 27 MR. GIBBONS: Well, we haven't quantified what 28 the costs would be of reducing emissions beyond that Les Services StenoTran Services Inc. 613-521-0703 2794 POLLUTION PROBE PANEL 1, cr-ex (Campbell) 1 level so I wouldn't want to say. 2 MR. CAMPBELL: Now, your counsel referred, in 3 asking you questions in your direct testimony, to the 4 document "Pollution Loopholes". Correct? 5 MR. GIBBONS: My counsel referred to the fact 6 that I had written that, yes. 7 MR. CAMPBELL: Yes. 8 As I understand it, the main thesis there is 9 that the pollution control approach approved by the 10 government will be ineffective because it does not 11 impose legally binding caps on companies other than OPG. 12 Is that a fair, overall conclusion? 13 MR. GIBBONS: Yes. It is the proposed -- it 14 is the new regulations that are proposed by the 15 government. At the moment they are in the proposal 16 stage and they haven't been finally turned into 17 regulations. 18 Yes, one of the major weaknesses of that 19 proposal, in my opinion, is that OPG will be able to buy 20 emissions credits from companies that are not subject to 21 legally binding caps with respect to their total 22 emissions. 23 MR. CAMPBELL: In the course of this proposal, 24 the government undertook consultation on this proposal? 25 MR. GIBBONS: Yes, sir. 26 MR. CAMPBELL: In the course of that 27 consultation, did you or the organization you are 28 representing here today, make points about the need for Les Services StenoTran Services Inc. 613-521-0703 2795 POLLUTION PROBE PANEL 1, cr-ex (Campbell) 1 hard caps on companies other than OPG? 2 MR. GIBBONS: The Ontario Clean Air Alliance 3 did make those submissions, yes, sir. 4 MR. CAMPBELL: It is fair to say they made 5 them pretty loudly and pretty consistently? 6 MR. GIBBONS: Yes, sir. 7 MR. CAMPBELL: But to date, in light of the 8 Minister's proposal, it would be fair to say, would it 9 not, that the government has not fully agreed with that 10 approach. That is correct also, isn't it? 11 MR. GIBBONS: Yes, sir. 12 MR. CAMPBELL: Would you not -- 13 MR. GIBBONS: At least at this point in time. 14 The government has, I think, indicated that 15 they have planned to subject all major stationary 16 sources in Ontario eventually to a legally binding 17 emissions caps as I understand it. 18 MR. CAMPBELL: If the government had listened 19 to you on emissions caps, would you still be here 20 proposing that this Board approve net load billing? 21 MR. GIBBONS: Well, it also depends on the 22 level of the emissions caps. If the government's 23 proposal was exactly the same, except for the fact that 24 all companies that were allowed to trade would be 25 subject to legally binding emissions caps, I believe 26 that Pollution Probe would still be here because the 27 initial caps that were proposed, at least for OPG, are 28 not nearly as low as are necessary to fully protect Les Services StenoTran Services Inc. 613-521-0703 2796 POLLUTION PROBE PANEL 1, cr-ex (Campbell) 1 public health. 2 MR. CAMPBELL: If the government had adopted 3 these caps overall in the industry at this 83 per cent 4 level that you spoke of, would you be still here talking 5 about net load billing? 6 MR. GIBBONS: I think there is a good chance 7 we wouldn't. 8 MR. CAMPBELL: And why is that? 9 MR. GIBBONS: Because if you had such strict 10 emissions caps, you would have made a dramatic reduction 11 in emissions and that would be a huge step forward and 12 it would -- the benefit of gross versus net wouldn't be 13 nearly as significant. 14 MR. CAMPBELL: In point of fact, what would 15 have happened under that circumstance is that OPG would 16 have very little room to generate any coal-fired 17 electricity. Isn't that correct? 18 MR. GIBBONS: Well, if there was emissions 19 caps on OPG that reduced their emissions by 83 per cent 20 and if they couldn't buy credits from other companies, 21 then, yes, they wouldn't be able to generate much 22 coal-fired electricity. 23 MR. CAMPBELL: And again, that is a desirable 24 outcome from your point of view? 25 MR. GIBBONS: Yes. 26 MR. CAMPBELL: Now, Mr. Chernick, testifying 27 for the Green Energy Coalition, stated that in response 28 to -- I think it was, questions from Mr. Vlahos, he Les Services StenoTran Services Inc. 613-521-0703 2797 POLLUTION PROBE PANEL 1, cr-ex (Campbell) 1 said, it was his intention that -- 2 When asked a question by Mr. Vlahos, 3 Mr. Chernick said the following: 4 "I certainly wasn't turning the process 5 on its head and saying let's use 6 transmission rate setting primarily as an 7 environmental tool." (As read) 8 Would I be fair to conclude that you disagree 9 with Mr. Chernick because your testimony is clearly 10 attempting to do just that, to take transmission rate 11 setting to achieve environmental goals that really you 12 have been unable to achieve directly through 13 environmental regulation? 14 MR. GIBBONS: No, sir. I don't believe that 15 what I am proposing is to use transmission rates to 16 achieve environmental goals. 17 I am recommending that we stick with the 18 status quo rate design philosophy for transmissions rate 19 which is user pay and net load billing. I am basically 20 advocating the status quo, which is a user pay 21 philosophy, and the status quo was never designed to 22 achieve public health or environmental objectives. 23 I believe that your clients, sir, and Ontario 24 Hydro Networks are trying to use transmission rate 25 setting to achieve certain objectives, one of which is 26 to discourage the construction of new natural gas 27 combined cycle generation in this province. 28 So I believe that you, sir, your client and Les Services StenoTran Services Inc. 613-521-0703 2798 POLLUTION PROBE PANEL 1, cr-ex (Campbell) 1 Ontario Hydro Networks, is trying to engage in a type of 2 social engineering through the transmission rate. 3 MR. CAMPBELL: Well, Mr. Gibbons, I think, 4 beauty being in the eye of the beholder, we will leave 5 the rest of this for argument. 6 Thank you very much, Mr. Chairman. 7 Those are my questions. 8 THE PRESIDING MEMBER: Thank you. 9 Mr. Lyle. 10 MR. LYLE: Thank you, Mr. Chair. 11 EXAMINATION 12 MR. LYLE: Mr. Gibbons, I have been asked by 13 Mr. Poch of Green Energy Coalition to ask you a couple 14 of questions. 15 I am going to refer you back to a document 16 that others have discussed, the document entitled 17 "Pollution Loopholes" dated February 2000. I believe 18 you were the author of that document? 19 MR. GIBBONS: Yes, sir. 20 MR. LYLE: I am going to have that document 21 entered as Exhibit G14.5. 22 EXHIBIT NO. G14.5: Document entitled 23 "Pollution Loopholes" dated February 24 2000, authored by Mr. Jack Gibbons 25 --- Pause 26 MR. LYLE: I understand this document analyzes 27 the recent announcement by the Minister of the 28 Environment with respect to the proposed to new NOx and Les Services StenoTran Services Inc. 613-521-0703 2799 POLLUTION PROBE PANEL 1, ex (Lyle) 1 SOx emission caps for OPGI, the emission performance 2 standards for electricity imports into Ontario and a 3 proposed emissions trading system. Is that correct? 4 MR. GIBBONS: Yes, sir. 5 MR. LYLE: I think you have addressed this in 6 part, but perhaps you could outline for me briefly the 7 gaps that you see with this proposed new package of 8 regulations. 9 MR. GIBBONS: Okay. Well, there are a number 10 of gaps. 11 Under the Ministry's proposal, the proposed 12 emissions caps and the proposed emissions performance 13 standards with respect to import only apply to two 14 pollutants, sulphur dioxide and nitrogen oxide whereas 15 there are at least 10 serious pollutants associated with 16 coal-fired powered power plants. So we have at least 17 eight serious air pollutants that are not subject to any 18 environmental regulations -- or any new environmental 19 regulations. 20 Another weakness, in our view, is that the 21 proposed emissions caps and the proposed emissions 22 performance standards are too high. They are not nearly 23 as low as they should be to fully protect public health. 24 A major loophole is that Ontario Power 25 Generation can exceed its nominal emissions caps by 26 buying credits from other companies in Ontario or the 27 United States that are not subject to legally binding 28 emissions caps. Les Services StenoTran Services Inc. 613-521-0703 2800 POLLUTION PROBE PANEL 1, ex (Lyle) 1 Under a legitimate emissions cap and trade 2 system such as was recommended by the Market Design 3 Committee, the only companies that buy and sell 4 emissions credits are companies that are subject to a 5 legally binding emissions cap, but under this proposal, 6 and under that scenario, if OPG was to exceed its 7 emissions caps by say ten tonnes, it would have to buy 8 emissions credits from other companies who have reduced 9 their emissions by ten tonnes below their cap, so the 10 net impact of trading is not to increase overall 11 emissions in the Ontario air shed. 12 The Ministry's proposal allows OPG to buy 13 credits from companies that are not subject to legally 14 binding emissions caps and who have not reduced their 15 total emissions. Under this scenario, when OPG 16 increases its emissions by ten tonnes over its emissions 17 cap, there's no requirement that ten tonne increase be 18 offset somewhere else in Ontario's air shed. 19 As a result of the emissions trading, not only 20 can OPG's emissions rise, but total emissions in the 21 Ontario air shed can rise. Those are our sort of 22 fundamental critique of the proposal from a big picture. 23 There are a number of other smaller criticisms that we 24 have, but those are the fundamental issues. 25 MR. LYLE: Thank you, sir. I will turn away 26 now from speaking on behalf of Mr. Poch and just ask you 27 one question with respect to your evidence. 28 If I understand your evidence, you have set Les Services StenoTran Services Inc. 613-521-0703 2801 POLLUTION PROBE PANEL 1, ex (Lyle) 1 out what the emission reductions would be if 1,950 2 megawatts of new gas fired embedded generation was built 3 out into the year 2008. Now, with respect to the OHNC 4 proposal for gross load billing, it's not your belief 5 that that's going to result in none of that generation 6 capacity being built. Is that correct? 7 MR. GIBBONS: No. I don't have a forecast of 8 how much generation would be built on a gross load 9 billing. 10 MR. LYLE: Those are all my questions. 11 THE PRESIDING MEMBER: Thank you. 12 Mr. Rogers. 13 MR. ROGERS: Just a few questions. 14 CROSS-EXAMINATION 15 MR. ROGERS: Mr. Gibbons, just following up on 16 Mr. Lyle's questions, to the extent that this 17 cogeneration is built, then your theory is emissions 18 would be reduced. If half of that was put into place, 19 in the face of my client's proposal, then the emissions 20 that you have calculated would be halved. 21 MR. GIBBONS: Oh, yes, sir. 22 MR. ROGERS: I'm just curious about a sort of 23 a comment you made to Mr. Campbell. You were here this 24 morning, weren't you, Mr. Gibbons? 25 MR. GIBBONS: Yes. 26 MR. ROGERS: And you heard the TransAlta 27 witnesses testify? 28 MR. GIBBONS: Yes. I wasn't always paying Les Services StenoTran Services Inc. 613-521-0703 2802 POLLUTION PROBE PANEL 1, cr-ex (Rogers) 1 extremely closely attention, but -- 2 MR. ROGERS: Mr. Gibbons, I'm surprised at 3 that. You know they are proponents of -- they want to 4 build cogeneration facilities here in Ontario. You know 5 that? 6 MR. GIBBONS: Yes, sir. 7 MR. ROGERS: They are proponents of a rate 8 structure which would facilitate that obviously. Right? 9 MR. GIBBONS: They certainly want to build gas 10 plants in Ontario. I understand that. Yes. 11 MR. ROGERS: But you did hear them say that 12 they understood the argument on the other side of this 13 equation that there has to be some protection for the 14 remaining customers when load leaves the system. 15 MR. GIBBONS: Right. 16 MR. ROGERS: Do you agree with that? 17 MR. GIBBONS: Well, I believe if we go to net 18 load billing, there will be adequate protection because 19 the customers who are still on the system for all of 20 their electricity needs will see their real transmission 21 rates decline. 22 MR. ROGERS: Yes. All right. You said that. 23 So you do agree that there is a need to do something to 24 protect the remaining customers who are being asked to 25 bear those costs, which are being avoided by customers 26 who install cogeneration. 27 MR. GIBBONS: Well, I don't think there's a 28 need to do anything extra. I mean if we go to net load Les Services StenoTran Services Inc. 613-521-0703 2803 POLLUTION PROBE PANEL 1, cr-ex (Rogers) 1 billing, you stay with the status quo. They will be 2 adequately protected. They will see their real rates 3 decline, plus they will benefit from cleaner air. 4 MR. ROGERS: Yes. Thank you. But my 5 question, would you answer it? You agree that something 6 has to be done to account for the fact that those 7 customers are picking up most costs than they were 8 before? 9 MR. GIBBONS: I'm not trying to be difficult, 10 Mr. Rogers, and I certainly agree that equity is an 11 important principle, it must be taken into account in 12 rate design. I would certainly agree that, you know, if 13 under net load billing real rates were forecast to rise 14 significantly, that would be a serious problem. 15 I'm not sure what you are getting at when you 16 say that something else has to be done. 17 MR. ROGERS: Just what TransAlta said this 18 morning, that they recognize, as I understood their 19 evidence, although they are proponents of net load 20 billing, they recognize that there has to be some except 21 provisions to protect remaining customers with respect 22 to the sunk costs of the system. Do you agree with 23 that? 24 MR. GIBBONS: No, sir, not above and beyond 25 what net load billing would produce. 26 MR. ROGERS: I see. All right. And what net 27 load billing will produce, in your view, is that it will 28 reduce air emissions, number one. Les Services StenoTran Services Inc. 613-521-0703 2804 POLLUTION PROBE PANEL 1, cr-ex (Rogers) 1 MR. GIBBONS: Yes, sir. 2 MR. ROGERS: And you said as well that it 3 won't produce it, but it will result in real electricity 4 rates which should decline for the transmission system 5 in the future. 6 MR. GIBBONS: Yes, sir. 7 MR. ROGERS: Of course, those real prices 8 would decline even further if no cogeneration was put 9 in, wouldn't they? 10 MR. GIBBONS: Yes, sir. 11 MR. ROGERS: All right. Those are my 12 questions. Thank you. 13 Oh, no, one other question if I could. I'm 14 just curious. You said that you thought that OPG was 15 against net load billing as was my client because they 16 wanted to discourage gas use for electricity production. 17 MR. GIBBONS: Well, that would certainly be 18 the effect of what you are proposing. 19 MR. ROGERS: I know, but I was curious. Why 20 would OHNC have an incentive to do that? 21 MR. GIBBONS: Well, I mean you are asking me 22 to speculate. 23 MR. ROGERS: You said that. What did you 24 mean? 25 MR. GIBBONS: Okay, but now you are asking me 26 why OHNC might have an incentive to do that. 27 MR. ROGERS: You spoke -- 28 MR. KLIPPENSTEIN: As I recall, Mr. Gibbons Les Services StenoTran Services Inc. 613-521-0703 2805 POLLUTION PROBE PANEL 1, cr-ex (Rogers) 1 was speaking just of OPG. 2 MR. ROGERS: No. He lumped them together. I 3 noted that. I'm quite sure of that. Perhaps I 4 misunderstood you. Did I, Mr. Gibbons? 5 MR. GIBBONS: I think in the question you just 6 put to me was why would OHNC have an incentive to 7 discourage gas fired generation? If that's your 8 question, I can certainly give a speculative answer why 9 that might be the case. 10 MR. ROGERS: Well, maybe we are wasting time. 11 Maybe I misunderstood you. Didn't you say that in your 12 evidence? 13 MR. GIBBONS: Say what, sir? 14 MR. ROGERS: That OPG and OHNC had an 15 incentive to discourage gas fired electrical production. 16 MR. GIBBONS: I might -- I certainly may have 17 said that and if you want me to explain why I believe 18 that -- 19 MR. ROGERS: Yes, I would. Just with respect 20 to my client. I understand that with the generator. I 21 need to understand it with respect to the transmission 22 company. 23 MR. GIBBONS: Yes. Okay. With respect to a 24 transmission company, it's my experience with 25 corporations that all corporations like to grow and 26 become bigger. Ontario Hydro Network Companies is a 27 transmission company. I would expect that its employees 28 and its senior management and possibly its Board of Les Services StenoTran Services Inc. 613-521-0703 2806 POLLUTION PROBE PANEL 1, cr-ex (Rogers) 1 Directors would like to see the company grow and become 2 a larger transmission company. 3 Now, if we have a new gas fired generation, 4 especially on a dispersed basis, built at plants like 5 Dofasco or at the paperboard plant down at the Portlands 6 in Toronto, what will happen is we would not need as 7 much transmission capacity and there won't be as many 8 growth opportunities for OHNC. 9 Basically, when we are moving to a dispersed 10 generation, the transmission -- there will be less use 11 of high voltage transmission lines because loads will be 12 closer to the ultimate customer. 13 MR. ROGERS: I see. Is that really why you 14 think Dr. Poray and Mr. Curtis recommended this 15 compromise basis of net load billing? 16 MR. GIBBONS: I'm sure many factors went into 17 their decision to recommend it, but if you ask me what 18 was OHNC's incentive, that was my answer. That's what 19 is the incentive. 20 MR. ROGERS: You aren't suggesting that's the 21 real reason for the proposal, are you? Maybe you are. 22 MR. GIBBONS: Maybe it's one of the reasons. 23 I think there are probably multiple reasons. 24 MR. ROGERS: All right. That's your belief 25 anyway, is it? 26 MR. GIBBONS: I certainly believe that 27 companies, utilities, like to grow and I certainly 28 believe if we go to net load billing, there will be less Les Services StenoTran Services Inc. 613-521-0703 2807 POLLUTION PROBE PANEL 1, cr-ex (Rogers) 1 load growth over time for Ontario Hydro Network 2 Corporation. I would certainly believe that would be 3 one reason why they would prefer gross load billing. 4 This is a complicated subject and I would not 5 want to suggest that was the only reason why OHNC is 6 proposing gross load billing. 7 MR. ROGERS: Very well. Thank you very much. 8 Thank you, sir. 9 THE PRESIDING MEMBER: Mr. Vlahos. 10 MEMBER VLAHOS: Mr. Gibbons, just a notation. 11 In your direct testimony, you quoted the Act as saying 12 it is to promote competition. I'm sure you did not mean 13 to promote competition. It is to facilitate 14 competition. 15 MR. GIBBONS: Sure. I'm sorry. 16 MEMBER VLAHOS: Thank you. 17 THE PRESIDING MEMBER: Mr. Smith. 18 MEMBER SMITH: A question on the matter of the 19 studies that suggest that air pollution creates 20 premature death and the implication of that in terms of 21 the cost to the externality. 22 I don't think anybody would dispute that 23 premature death is a bad thing in itself, even if it 24 didn't cost anything to anybody, even if it somehow 25 benefited in another regard. It's something to be 26 avoided. 27 People go on to suggest that premature death 28 imposes costs on the state that did not exist with Les Services StenoTran Services Inc. 613-521-0703 2808 POLLUTION PROBE PANEL 1 1 so-called mature death. I think maybe you didn't say it 2 in your testimony, but I thought you alluded to the fact 3 that premature death creates a burden on the state that 4 it wouldn't otherwise bear in terms of medical services. 5 I just wondered if there is any studies or 6 research behind that that you could point me to that I 7 might not be aware of. 8 MR. GIBBONS: I'm not exactly sure. The 9 1,800 premature deaths, that is a Government of Ontario 10 statistic, Ministry of the Environment. It is referred 11 to in their smog plan for Ontario. If you look, I think 12 the smog plan for Ontario summarizes some of the 13 benefits of reducing pollution and I think it gives an 14 overview of the cost benefit. That is in the smog plan 15 document. 16 Then there is a whole series of appendices, a 17 very thick document, that I believe has a lot of 18 information about the health cost savings if we could 19 reduce air pollution. 20 Now, whether in that report they actually 21 dealt with the issue of maybe the premature death part 22 is actually a benefit in terms of reducing health care 23 costs, I don't know. 24 I definitely know that -- I mean, there are 25 obviously a lot of health care costs that aren't as 26 acute, that don't lead to death. But, you know, having 27 kids with asthma attacks in the emergency wards and that 28 obviously incur costs for the taxpayer. Les Services StenoTran Services Inc. 613-521-0703 2809 POLLUTION PROBE PANEL 1 1 Those reports, I think you would find a wealth 2 of information there if you looked at them in detail. I 3 haven't read them in detail, but that is one place you 4 can look. 5 I do know that the Ontario Medical Association 6 is working on a report about the health care cost of air 7 pollution, how much air pollution increased health care 8 costs and I believe they are planning to release it in 9 May. 10 MEMBER SMITH: Thank you. 11 THE PRESIDING MEMBER: There are no other 12 questions from the Board. 13 Thank you. 14 MR. GIBBONS: Thank you. 15 THE PRESIDING MEMBER: Mr. Klippenstein. 16 MR. KLIPPENSTEIN: I have no re-direct, 17 Mr. Chair, so that is the evidence from Pollution Probe. 18 Thank you. 19 THE PRESIDING MEMBER: Thank you, Mr. Gibbons. 20 MR. ROGERS: Does the Board feel able to hear 21 me and Mr. Snelson complete our discussions this 22 afternoon? 23 THE PRESIDING MEMBER: Yes. That's right. 24 Do you think we should take a break or are you 25 ready to go? 26 MR. ROGERS: I would suggest we take a short 27 break, sir. If you want to take a break, now is a good 28 time. I expect to be 30 or 40 minutes perhaps with Les Services StenoTran Services Inc. 613-521-0703 2810 1 Mr. Snelson. 2 THE PRESIDING MEMBER: Fine. Okay. 3 We will take a short break. Ten minutes. 4 Thank you. 5 --- Upon recessing at 1458 6 --- Upon resuming at 1522 7 THE PRESIDING MEMBER: So it's getting warm in 8 here, by the way so if anybody wishes to take their 9 jacket off or something, please do so. All right. 10 MR. ROGERS: Thank you very much. 11 Are you ready? 12 Mr. Campbell has something he would like 13 to say. 14 MR. CAMPBELL: Mr. Chairman, I just wanted to 15 let you know that we have filed answers to 16 Undertakings 10.1 and 12.2. Ten-point-one is the one 17 dealing with export and wheel through charges and you 18 may want to look at that before OPG comes on tomorrow, 19 which is why I bring it particularly to your attention. 20 THE PRESIDING MEMBER: Yes. Okay, thank you, 21 Mr. Campbell. 22 Okay, good. We will go then. 23 MR. ROGERS: Very well. Dr. Higgin and 24 Members of the Board, I will refer again to Exhibit 9.2 25 which was a series of diagrams that -- 26 THE PRESIDING MEMBER: Yes. You provided us a 27 copy. 28 MR. ROGERS: -- we dealt with about two weeks Les Services StenoTran Services Inc. 613-521-0703 2811 1 ago. Exhibit 9 -- I think it's G9.2. 2 THE PRESIDING MEMBER: G9 -- something like 3 that. 4 --- Pause 5 THE PRESIDING MEMBER: Okay. We are all set 6 here. 7 MR. ROGERS: I think I have an extra copy 8 here, if you would like. It's in my pile somewhere. 9 THE PRESIDING MEMBER: We can share this one. 10 MR. ROGERS: All right. Thank you very much. 11 This won't take too long, I hope. 12 --- Pause 13 PREVIOUSLY SWORN: KENNETH SNELSON 14 CONTINUED CROSS-EXAMINATION BY MR. ROGERS 15 MR. ROGERS: These are technical areas and I 16 hope the diagram will help follow this. 17 First of all, if we could just revisit where 18 we were a week or so ago, Mr. Snelson, you may recall 19 that we had been discussing examples on pages 1 and 2 of 20 this exhibit, Figure N1 and N2, and we had been talking 21 about some of the complexities of managing and 22 regulating the narrowly defined line connection pool 23 which you proposed. Do you recall that? 24 MR. SNELSON: I recall that, yes. 25 MR. ROGERS: And we had talked about how some 26 customers could move in and out of the pool, and so 27 on, -- and I don't want to revisit all of that. 28 MR. SNELSON: We had talked about how as the Les Services StenoTran Services Inc. 613-521-0703 2812 AMPCO PANEL 1, cr-ex (Rogers) 1 system changes and there may be need to readjust, yes. 2 MR. ROGERS: That's right. We concluded, I 3 think, with the discussion about how, as customers 4 bought their lines, as you proposed, the pool would 5 disappear. 6 MR. SNELSON: Yes, I had mentioned that I 7 believed that specific costing and pooling are not 8 consistent on a long-term basis and one will take over 9 the other. 10 MR. ROGERS: All right. Very good. That is 11 where we left off. 12 Now, I would like to then move on to discuss 13 with you new investment, because our discussion last 14 week dealt with existing investment. 15 To do this, I would like to look at Figure N3, 16 the third page, please. 17 MR. SNELSON: I have it in front of me. 18 MR. ROGERS: This perhaps requires a little 19 explanation for the Board, although I'm sure you figured 20 this out, Mr. Snelson. 21 What this diagram shows, Dr. Higgin and 22 Members of the Board, is that the network pool is shown 23 diagrammatically at the top of the page in the dark 24 area. That's the network pool as proposed by my client. 25 Over that you will see a crosshatched area and below 26 that again another dark shaded area, which is labelled 27 the narrow connection pool. 28 The narrow connection pool at the bottom of Les Services StenoTran Services Inc. 613-521-0703 2813 AMPCO PANEL 1, cr-ex (Rogers) 1 the page, Cost D, is the narrow connection pool proposed 2 by Mr. Snelson. 3 Do you follow me, Mr. Snelson? 4 MR. SNELSON: I believe so, as far as you have 5 gone anyway. 6 MR. ROGERS: All right. That's fine. 7 Just to help here -- I think I have this 8 right -- that under my client's proposal the line 9 connection pool would consist of the middle crosshatched 10 shaded area and the bottom highly shaded area. 11 MR. SNELSON: Is that with all the facilities 12 shown here or only with those that have solid lines? 13 MR. ROGERS: Solid lines. 14 MR. SNELSON: Okay. 15 MR. ROGERS: Okay? 16 Under your proposal with the narrow connection 17 pool you had defined it, which diagrammatically we have 18 shown at the bottom of the page in the dark area, 19 Cost D, and everything else, including the crosshatched 20 area you had put into the network pool, under your 21 proposal? 22 MR. SNELSON: I have a bit of difficulty with 23 the right-hand side of the diagram. 24 The left-hand side of the diagram -- 25 MR. ROGERS: You understand. 26 MR. SNELSON: -- this is our Customer C2 and 27 C1, existing customers and new customers. 28 MR. ROGERS: We will talk about the customers Les Services StenoTran Services Inc. 613-521-0703 2814 AMPCO PANEL 1, cr-ex (Rogers) 1 in a moment, but if you could just ignore those for a 2 moment until we establish -- I want to be sure you 3 understand what this diagram shows. 4 MR. SNELSON: I want to be sure I understand 5 that too, and if C2 and C1 are not existing customers -- 6 MR. ROGERS: They are existing customers. 7 MR. SNELSON: Oh, they are existing customers? 8 MR. ROGERS: Yes. 9 MR. SNELSON: Because I had understood in the 10 previous diagram that dotted lines meant new facilities 11 that were to be added. 12 MR. ROGERS: The doted lines are 13 customer-owned lines -- 14 MR. SNELSON: Customer-owned lines. 15 MR. ROGERS: -- just as on the previous 16 diagram. 17 MR. SNELSON: Okay. I'm sorry. That was 18 something I didn't understand. 19 MR. ROGERS: All right. 20 MR. SNELSON: So with that clarification, yes 21 I agree with that statement you just made. 22 MR. ROGERS: Good. I hope the Board has 23 followed this. I will try to make this clear as we go 24 through this. 25 Now, let's look at a few of these customers, 26 Mr. Snelson. 27 Up at the top right-hand corner, you will see 28 Customer No. 7 -- Les Services StenoTran Services Inc. 613-521-0703 2815 AMPCO PANEL 1, cr-ex (Rogers) 1 MR. SNELSON: Yes. 2 MR. ROGERS: -- and because he has a dotted 3 line there, that signifies that he owns or has built and 4 owns his own line. 5 MR. SNELSON: I understand that now, yes. 6 MR. ROGERS: And he is connected to a network 7 station, as indicated by that dashed line. Do you see 8 that? 9 MR. SNELSON: Yes. 10 MR. ROGERS: Now, under your proposal would 11 this customer pay toward the revenue requirement for the 12 costs shown in the network facilities at the top of the 13 page as well as the crosshatched middle portion of this 14 diagram? 15 MR. SNELSON: Just to clarify, are you saying 16 he owns his own connection to the network station? 17 MR. ROGERS: Yes. 18 MR. SNELSON: Then he would not be in the 19 narrowly defined connection pool because he owns his own 20 connection. 21 MR. ROGERS: That's right. 22 Does that mean he would then pay, though, for 23 all of the network costs in your broad network 24 definition which consists of the shaded area at the top 25 as well as the cross-hatched area which now would fall 26 into the network definition under your proposal? 27 MR. SNELSON: Yes, he would. 28 MR. ROGERS: Whereas under my client's Les Services StenoTran Services Inc. 613-521-0703 2816 AMPCO PANEL 1, cr-ex (Rogers) 1 proposal he would not? 2 MR. SNELSON: That is correct. 3 MR. ROGERS: If we look at the Customer C8 4 down at the bottom of that, the bottom right-hand side 5 of the page -- 6 MR. SNELSON: Yes. 7 MR. ROGERS: -- once again you see the 8 cross-hatched line so we know that Customer 8 has paid 9 for his dedicated facilities. 10 MR. SNELSON: Yes. 11 MR. ROGERS: Will he pay towards the revenue 12 requirement for the costs of the bigger network pool 13 that you propose? 14 MR. SNELSON: Yes, he will. 15 MR. ROGERS: Okay. Thank you. 16 Can we go to Exhibit D, Tab 4, Schedule 4, 17 please. This is my client's application. 18 THE PRESIDING MEMBER: Can we just clarify why 19 Customer C3 on the top left -- is it just the hatched -- 20 MR. ROGERS: I'm sorry, sir. That should be a 21 dashed line, customer-owned line, C3 at the top left. 22 THE PRESIDING MEMBER: Okay. Thank you. 23 MR. ROGERS: Thank you very much for pointing 24 that out. 25 Can we look at Exhibit D, Tab 4, Schedule 4, 26 page 17 of 19. 27 --- Pause 28 MR. SNELSON: I'm sorry, which page number was Les Services StenoTran Services Inc. 613-521-0703 2817 AMPCO PANEL 1, cr-ex (Rogers) 1 that? 2 MR. ROGERS: Exhibit D, Tab 4, Schedule 4, 3 page 17. 4 MR. SNELSON: I have that, yes. 5 MR. ROGERS: I want to look at the order of 6 magnitude of the cost that we are talking about here, 7 Mr. Snelson. Now, if we look at this diagram, in the 8 very middle column there is a heading for "Total Annual 9 Line Connection Charges". 10 MR. SNELSON: I see that. 11 MR. ROGERS: This happens to be under 12 Option XVI, but I don't think it matters. The same 13 figures apply to Option XVIII. It shows that for the 14 directs under that total annual line connection charges 15 there is about $26 million allocated to the direct 16 customers. 17 MR. SNELSON: I can see that, yes. 18 MR. ROGERS: Below that, if I look down a 19 couple of lines, I see that the balance is $188 million 20 of line connection pool charges which are paid for by 21 the LDCs. 22 MR. SNELSON: I think the LDCs paid the 23 $138.15 million. 24 MR. ROGERS: Yes, you are right. I'm sorry. 25 I'm sorry. It is $26 million of the total of 26 $188 million. I apologize. 27 MR. SNELSON: The directs pay $26 million out 28 of $188 million. Les Services StenoTran Services Inc. 613-521-0703 2818 AMPCO PANEL 1, cr-ex (Rogers) 1 MR. ROGERS: Correct. I'm sorry. 2 MR. SNELSON: That is what the figures show, 3 yes. 4 MR. ROGERS: Right. So that is about 14 per 5 cent of the line connection charges. 6 MR. SNELSON: I haven't done the calculation 7 but it is approximately right, yes. 8 MR. ROGERS: The point I wanted to make is 9 that the direct customers, many of whom you represent, 10 comprise about 14 per cent of the revenue collected for 11 this particular charge or they contribute about 14 per 12 cent of the total charge under my client's proposal. 13 MR. SNELSON: That is what OHNC's figures 14 show, yes. 15 MR. ROGERS: Right. 16 The rest of the line collection charges are 17 paid by the LDCs and their customers. 18 MR. SNELSON: Well, some is paid by OHNCD, 19 which is an LDC, I trust, in this analysis. 20 MR. ROGERS: Yes, it is. 21 And the point, the simple point I would like 22 to make is that -- we will have to wait for the 23 arguments -- so far as I'm aware from what I have 24 observed in these hearings none of these remaining 25 customers who are paying the vast majority of these 26 charges have any complaint about the proposal of my 27 client. Do you agree with that, with respect to this 28 particular component? Les Services StenoTran Services Inc. 613-521-0703 2819 AMPCO PANEL 1, cr-ex (Rogers) 1 MR. SNELSON: As you say, we have not had very 2 much from the Municipal Electric Association, so I'm 3 responding on behalf of AMPCO and I'm not really 4 speaking for the other customers. 5 MR. ROGERS: I know you are not, but does it 6 not appear to you that you have the 14 per cent tail 7 wagging the remaining dog? 8 MR. SNELSON: The proportions are as you have 9 shown them. AMPCO has the concerns that we have talked 10 about and $26 million is a substantial sum of money. 11 MR. ROGERS: We will wait to hear what the 12 other 86 per cent of the customers have to say in their 13 argument I suppose. 14 Could we turn to Exhibit E-2-1, which may help 15 us here. That is a response by my client to one of your 16 interrogatories. 17 MR. SNELSON: I can see that. Yes, I have 18 that in front of me. I had the advantage of knowing you 19 were going to refer to it. 20 MR. ROGERS: Exhibit E, Tab 2, Schedule 1, at 21 Appendix E2-1. 22 --- Pause 23 MR. ROGERS: Exhibit E, Tab 2, Schedule 1, and 24 I would like to look at the appendix at E2-1:B, which is 25 in about five or six pages into the document. 26 --- Pause 27 MR. ROGERS: It's Appendix E2-1:B. It is on 28 the left-hand side. Les Services StenoTran Services Inc. 613-521-0703 2820 AMPCO PANEL 1, cr-ex (Rogers) 1 THE PRESIDING MEMBER: We have it. 2 MR. ROGERS: Thank you. 3 If we look at the table on the left side, 4 Mr. Snelson -- this is an allocation of transmission 5 costs that are set out there -- it is noted that under 6 the AMPCO proposal, the revenue requirements of the line 7 connection pool would reduce to $51 million from 8 $189 million as under my client's proposal. Is that 9 right? 10 MR. SNELSON: Yes, that's what your 11 calculations show. Yes. 12 MR. ROGERS: So in the middle line there you 13 can see that it goes from $189 million down to 14 $51 million under your proposal for an interline 15 connection. 16 MR. SNELSON: That is correct. 17 --- Pause 18 MR. ROGERS: I'm instructed that the 19 $51 million represents about 5 per cent of the revenue 20 requirement, more or less. My question to you really 21 is: Is it really worth all the complications that it 22 causes to go to this narrow pool to have such a small 23 pool remaining? Why bother with it? 24 MR. SNELSON: My calculations show that it is 25 4.4 per cent. We did that calculation and we responded 26 to that kind of thought in one of the interrogatory 27 responses, and that is E, Tab 49, Schedule 4. 28 MR. ROGERS: Can you just tell us what you Les Services StenoTran Services Inc. 613-521-0703 2821 AMPCO PANEL 1, cr-ex (Rogers) 1 said? 2 MR. SNELSON: And we also referred to it in 3 our direct evidence in which we said that with such a 4 small pool remaining and an even smaller number of 5 customers remaining in the pool, then there was some 6 consideration -- AMPCO gave some consideration to 7 perhaps proposing that the line connection pool be 8 amalgamated with the transformation connection pool to 9 create one pool which has the common characteristics of 10 being a connection and that that was one way of avoiding 11 the complexity of an additional pool solely for the 12 purpose of collecting less than 5 per cent of the 13 revenue requirement. 14 MR. ROGERS: So your proposal is that it be 15 merged with the transformation connection pool? 16 MR. SNELSON: AMPCO would accept the merging 17 of it with the transformation connection pool provided 18 the buyout of connection assets were to be approved. 19 MR. ROGERS: The buyout. Of course you want 20 the buyout at net book value. 21 MR. SNELSON: We had proposed net book value, 22 yes. 23 MR. ROGERS: Suppose the Board doesn't agree 24 with you and they don't want it at net book value, they 25 say it has to be at replacement cost with some 26 consideration for reduction for the depreciation on the 27 line, what is your proposal then? 28 MR. SNELSON: I think AMPCO would want to Les Services StenoTran Services Inc. 613-521-0703 2822 AMPCO PANEL 1, cr-ex (Rogers) 1 consider that as a possibility. The purpose of 2 proposing net book value is that is the value that is 3 recorded on the books of OHNC, that is the value on 4 which they are being allowed to earn a return in their 5 revenue requirement. If that was to be removed, then 6 you are not putting additional costs on to other 7 customers. You are taking out some costs and you are 8 taking out an equivalent amount of earnings potential. 9 MR. ROGERS: Well, if you did what you 10 suggested and put these costs into the transformation 11 connection pool, the cost in that of the customers who 12 paid for that merged connection pool would be 13 dramatically increased, wouldn't they? 14 MR. SNELSON: They would be increased by -- 15 and I believe the reference is in the interrogatory -- 16 MR. ROGERS: I believe it's about 17 per cent. 17 MR. SNELSON: I believe they would be 18 increased by 17 per cent, assuming that all the 19 customers who are in the line connection pool are also 20 in the transformation connection pool. So there is some 21 uncertainty in that estimation, according to how those 22 customers are allocated between the two pools. 23 MR. ROGERS: Seventeen per cent is quite a 24 major shift. 25 MR. SNELSON: Seventeen per cent is a 26 substantial increase and -- but it would be offset by 27 more than that for those who would have been in the line 28 connection pool anyway. Les Services StenoTran Services Inc. 613-521-0703 2823 AMPCO PANEL 1, cr-ex (Rogers) 1 So it will be a shift upwards for a customer 2 who is only in the transformation connection pool; it 3 will be a shift downwards for those who are in both 4 pools. 5 MR. ROGERS: Why wouldn't you just put -- if 6 this pool was so small not to justify the bother and 7 complications it causes, why not put them all in the 8 network pool? 9 MR. SNELSON: It depends on what you are 10 trying to achieve, with respect to a customer's 11 responsibilities for his own assets. 12 I believe there was some discussion earlier -- 13 and it followed on from thoughts in the Market Design 14 Committee process -- that one of the things that we are 15 trying to achieve is to make customers more directly 16 responsible for the costs that they impose on the system 17 and to give them some more opportunities to manage those 18 costs and to -- if they do that -- to avoid paying for 19 the costs that they have -- of other people who are not 20 paying for their own facilities. And if you put all of 21 the narrowly defined line connection costs back into the 22 network pool, then you are back with the problems that 23 we have got; that the investment rules, as proposed, 24 don't achieve that with shared assets. 25 MR. ROGERS: All right. Thank you. 26 Now, I understand that the interrogatory 27 response indicates -- I don't think we need to turn this 28 up, but it is Exhibit E, Tab 2, Schedule 26, page 12, Les Services StenoTran Services Inc. 613-521-0703 2824 AMPCO PANEL 1, cr-ex (Rogers) 1 Part A, tells us that there are about 246 customers that 2 do not pay transformation connection charges. 3 MR. SNELSON: Sorry. Could you give me that 4 again, please? 5 MR. ROGERS: Exhibit E, Tab 2 -- 6 MR. SNELSON: I am there now. 7 MR. ROGERS: Okay. That tells us, I think -- 8 and I don't have it myself -- but I believe there are 9 246 customers that do not pay transformation connection 10 charges. 11 MR. SNELSON: Are we talking about with the 12 narrow definitions or the long definitions of the...? 13 MR. ROGERS: Well, it is the same proposed; it 14 is transformation. So it is the same in OHNC's and 15 yours. 16 MR. SNELSON: Looking at line 9 of that -- 17 MR. ROGERS: Excuse me. I don't have it. I 18 didn't realize this was going to be a problem, 19 Mr. Snelson -- 20 MR. SNELSON: These numbers are new to me and 21 I don't want to confirm them unless I am sure we are 22 talking about the same numbers. 23 MR. ROGERS: All right. Let's look. Give me 24 a moment to find it, would you, please. 25 --- Pause 26 MR. ROGERS: I am looking at the table on the 27 left side of the page. 28 MR. SNELSON: Yes. Les Services StenoTran Services Inc. 613-521-0703 2825 AMPCO PANEL 1, cr-ex (Rogers) 1 MR. ROGERS: Under "Service Pools on Delivery 2 Point Basis Per OHNC Definition". 3 MR. SNELSON: Okay. And are you looking at, 4 then, the sum of the six and the eight and the ten who 5 pay more line or transformation charges than the 62, the 6 58 and 102? 7 MR. ROGERS: Yes. 8 There is quite a few of them. That is the 9 only point I am trying to make. I don't want to drag 10 this out. 11 MR. SNELSON: Well, I think your question said 12 "customers", and I believe these are delivery points. 13 MR. ROGERS: Oh, I am sorry. 14 MR. SNELSON: On the customer basis, above, 15 then, it was 64 -- or 62. But, then, there are a 16 substantial number of customers who do not pay 17 transformation charges, yes. 18 MR. ROGERS: And there are a lot of customers 19 who self-provide transformation now, aren't there? 20 MR. SNELSON: That is correct. 21 MR. ROGERS: So there is already healthy 22 competition in that area? 23 MR. SNELSON: Yes, there certainly is. 24 MR. ROGERS: Am I right, though, that the 25 number of customers that now self-provide any line 26 facilities is very low? 27 MR. SNELSON: I know the number of industrial 28 customers who own parts of their transmission lines. I Les Services StenoTran Services Inc. 613-521-0703 2826 AMPCO PANEL 1, cr-ex (Rogers) 1 also know of others who have paid for parts of their 2 transmission lines that don't own them. So, it depends 3 exactly what you mean by "self-provision", but there is 4 certainly less (inaudible) in the current system to 5 self-provide your transmission lines than there are 6 transformation facilities. 7 MR. ROGERS: Would you think that an estimate 8 of around 20 would be about right? 9 MR. SNELSON: Twenty who own all of their line 10 connection facilities, or some of their line connection 11 facilities? 12 MR. ROGERS: Some. 13 MR. SNELSON: I am afraid I couldn't confirm 14 that number; I haven't got enough -- 15 MR. ROGERS: All right. 16 MR. SNELSON: -- to be able to do that. 17 MR. ROGERS: All right. In any event, 18 wouldn't you think that whether that number is quite 19 right or not, that customers are generally more likely 20 to self-provide transformation, rather than line 21 connection, because transformation is located within 22 their own fenced property area? 23 MR. SNELSON: That is one factor, yes. 24 MR. ROGERS: And if you are going to have line 25 connections owned by a private delivery point, or a 26 customer, that involves rights-of-way which -- over 27 other people's property and so on? 28 MR. SNELSON: It may do, yes. Les Services StenoTran Services Inc. 613-521-0703 2827 AMPCO PANEL 1, cr-ex (Rogers) 1 MR. ROGERS: By the way, how would you go 2 about doing that? How would a customer acquire the 3 right-of-way to build to a transmission line? Without 4 expropriation powers and so on. 5 MR. SNELSON: I haven't thought through the 6 specifics of that. 7 I know that mining companies have, at times, 8 built their own transmission lines rather than having 9 Ontario Hydro Networks do it for them. And the exact 10 specifics of what legal or other procedural roles they 11 have to go through I am not familiar with. 12 MR. ROGERS: It is your proposal, isn't it, 13 that we should be encouraging people to build their own 14 transmission facilities? 15 MR. SNELSON: It is our proposal -- 16 MR. ROGERS: Sorry. Line connection 17 facilities. 18 MR. SNELSON: It is our proposal that we move 19 along the path that has been proposed by the Market 20 Design Committee of making customers more directly 21 responsible for the costs they impose on the 22 transmission system, and this is the first step in that 23 direction. And so, to that extent, yes. 24 MR. ROGERS: All right. Would you agree with 25 me that it would be very difficult for some company, or 26 person -- some company, more likely, or I suppose it 27 could be another entity -- but to build a network line 28 through a heavily populated area without powers of Les Services StenoTran Services Inc. 613-521-0703 2828 AMPCO PANEL 1, cr-ex (Rogers) 1 expropriation? 2 MR. SNELSON: I think we just shifted from 3 connection to network. 4 MR. ROGERS: Line connection. I am sorry, 5 Mr. Snelson. If I did use the wrong word, I apologize. 6 All I am trying to get at is, you are 7 advocating that we should be modifying our proposal to 8 encourage people to own their own connection facilities. 9 MR. SNELSON: Well, we -- 10 MR. ROGERS: Correct? That is your proposal, 11 isn't it, among others? 12 MR. SNELSON: That is our proposal. But we 13 had understood it to be a part of your proposal, too. 14 MR. ROGERS: My question to you is this, 15 though: How -- won't there be problems with building 16 line connection facilities through heavily populated 17 areas? 18 MR. SNELSON: There may well be. 19 MR. ROGERS: And it is your proposal to merge 20 the line connection and transformation connection pools, 21 and a customer would have to pay the merged line 22 connection charge -- which is about 17 per cent higher 23 than the transformation rate -- unless he also provides 24 the dedicated transmission line, won't he? 25 MR. SNELSON: Yes. 26 MR. ROGERS: Assuming he self-provides 27 transformation? 28 MR. SNELSON: Assuming he self-provides Les Services StenoTran Services Inc. 613-521-0703 2829 AMPCO PANEL 1, cr-ex (Rogers) 1 transformation. 2 MR. ROGERS: All right. Thank you. 3 Doesn't that provide a disincentive for a 4 customer to self-provide transformation? 5 MR. SNELSON: If you accept that it is more 6 difficult for the customer to build the tap line than it 7 would be for OHNC, yes. I'm not so sure that it's more 8 difficult for the customer to do it than it is for OHNC 9 to do it. 10 MR. ROGERS: Excuse me a moment, please. 11 --- Pause 12 MR. ROGERS: You were asked the other day, 13 Mr. Snelson, about the four pool approach. I think 14 counsel for Board staff suggested it. Do you recall 15 that? 16 MR. SNELSON: Yes, they did. 17 MR. ROGERS: And as I understand it, one of 18 those four pools would be the narrow line connection 19 pool. Is that your understanding? 20 MR. SNELSON: That's my understanding. 21 MR. ROGERS: Now, would you agree that the 22 complexities or anomalies if you prefer that we 23 discussed earlier with reference to figures N1 and N2 on 24 my exhibit would still apply even if the four pool 25 approach were adapted? 26 MR. SNELSON: Yes, they would. 27 MR. ROGERS: Thank you. Now, sir, one last 28 thing before we leave this topic. Could you please turn Les Services StenoTran Services Inc. 613-521-0703 2830 AMPCO PANEL 1, cr-ex (Rogers) 1 to Table 2-3 on page 11 of your testimony. Exhibit 2 H.2.1. 3 --- Pause 4 MR. ROGERS: It's a table and I don't know 5 whether we need to turn this up, Dr. Higgin. Sorry to 6 be jumping around so much. 7 Mr. Snelson, do you have it? 8 MR. SNELSON: Yes, I do. 9 MR. ROGERS: All I want to do is demonstrate 10 by this is that the effect of adopting your narrow 11 definition of the line connection pool is to shift $7 12 million in costs from -- out of the directs as compared 13 to my client's proposal. 14 MR. SNELSON: The difference between the 15 narrow definition and the broad definition is that with 16 the narrow definition, the costs allocated to the direct 17 customers go down, for instance, in alternative 16, from 18 $121 million to $114 million. That is a difference of 19 $7 million. 20 MR. ROGERS: Thank you. That is the point I 21 wish to make. You can take that from the two lines, 22 four up from the bottom, the narrow and the broad 23 definition. Right? 24 MR. SNELSON: Yes. 25 MR. ROGERS: All right. Thank you very much. 26 So, if the Board accepts your proposal, then the direct 27 customers will benefit to the extent of $7 million. 28 MR. SNELSON: As compared to your client's Les Services StenoTran Services Inc. 613-521-0703 2831 AMPCO PANEL 1, cr-ex (Rogers) 1 proposal, I point out, as I have said before, that 2 compared to the power district proposal, this is still 3 an increase in costs. 4 MR. ROGERS: Yes. All right. Thank you very 5 much. Now can we just change topics now slightly, 6 please. I would like to discuss your proposals for 7 charge determinants briefly. 8 I believe your proposal for the charge 9 determinant for network service now, for network service 10 is what has been referred to as Option XVI during the 11 process. 12 MR. SNELSON: That is correct. 13 MR. ROGERS: My client's proposal is 14 Option XVIII. 15 MR. SNELSON: I believe so. 16 MR. ROGERS: My client's proposal for network 17 charges is to use the higher of coincident peak load and 18 the hour of system peak at 85 per cent of the customer 19 peak during the peak period, which is defined as 7:00 20 a.m. to 7:00 p.m. 21 MR. SNELSON: Five days a week. 22 MR. ROGERS: Five days a week. 23 MR. SNELSON: Excluding statutory holidays. 24 MR. ROGERS: Yes. Thank you. Now, if you go 25 to the last page of my exhibit -- I'm sorry, the second 26 last page, N4 of Exhibit G9.2, we can discuss this 27 aspect, please. 28 If I can try to explain to the Board what this Les Services StenoTran Services Inc. 613-521-0703 2832 AMPCO PANEL 1, cr-ex (Rogers) 1 figure shows. You correct me if I'm wrong, Mr. Snelson, 2 but I believe that what is depicted here is the demand 3 of a customer that has 100 megawatts of load during the 4 peak hours of the month of January and that he has a 50 5 megawatt embedded generator that is operated for 100 6 hours during the month, during the peak hours of the 7 month. Do you see that? 8 MR. SNELSON: I see that. I'm not going to 9 correct your figure because it's your figure. I need to 10 understand it too. I'm not going to tell you what it is 11 because I don't fully understand it myself. 12 MR. ROGERS: Don't help me then. I will do it 13 myself. 14 MR. SNELSON: I will do the best I can, but 15 it's your figure. 16 MR. ROGERS: I'm just trying to explain to you 17 what I understand to be the case here. 18 MR. SNELSON: Okay. 19 MR. ROGERS: Because the Board really hasn't 20 looked at this before. What it is intended to show is a 21 customer who has 100 megawatts of demand during the 22 month of January. 23 MR. SNELSON: I can see that. Yes. 24 MR. ROGERS: You will see a shaded area there 25 that says "50 megawatts of generation". 26 MR. SNELSON: I also see that. Yes. 27 MR. ROGERS: That's intended to depict 50 28 megawatts of embedded generation behind the meter. Les Services StenoTran Services Inc. 613-521-0703 2833 AMPCO PANEL 1, cr-ex (Rogers) 1 MR. SNELSON: Okay. 2 MR. ROGERS: And it's operated, as you can see 3 from the diagram, in this example for 100 hours during 4 the month during the peak hours of the month. 5 MR. SNELSON: I can see that you have drawn it 6 that way. Yes. 7 MR. ROGERS: All right. Thank you. Now, the 8 horizontal axis of the figure shows the 240 peak hours 9 of the month, that is those hours between 7:00 a.m. and 10 7:00 p.m. five weekdays per week and four weeks for the 11 month. We have arranged these hours in descending order 12 of system load, that is the hour of highest system load 13 is hour number one and so on, which I think is a 14 technique often used for these types of analysis, would 15 you agree? 16 MR. SNELSON: Yes. That's called a system 17 load duration graph. 18 MR. ROGERS: You are quite familiar with them. 19 MR. SNELSON: I am reasonably familiar with 20 those. Yes. 21 MR. ROGERS: Now, the customer's net demand 22 used for this example is plotted in the bottom portion 23 of the graph. I should explain -- I'm sure you figured 24 this out, Mr. Snelson, but the system duration curve at 25 the top part of this graph shows the system load 26 duration curve for the peak hours of January. 27 Now, I am instructed that if the same scale 28 were used for the system duration curve as for the Les Services StenoTran Services Inc. 613-521-0703 2834 AMPCO PANEL 1, cr-ex (Rogers) 1 customer demand, then this curve would be way off the 2 page, so the curve is brought down to be on the same 3 page by dividing the system demand by 100 in each of the 4 hours. 5 If one wants to read the system demand in any 6 hour, one would either multiply the left hand scale by a 7 100 -- Do you understand that, Mr. Snelson? 8 MR. SNELSON: I understand that now you have 9 explained it. Yes. 10 MR. ROGERS: I don't think it matters. I just 11 wanted to put the load duration curve on the page to 12 compare it to the customer's load. 13 Now, first of all, do you agree that the 14 system duration curve for the month of January appeared 15 to you to be an accurate depiction of what it should be? 16 MR. SNELSON: I'm not sure which January this 17 is. It has the right form, but as regards the actual 18 numbers, I can't confirm or deny them. 19 MR. ROGERS: I'm instructed as for January of 20 2000 -- 21 MR. SNELSON: Is this actual numbers or is 22 this some forecast that was made last year or what? 23 MR. ROGERS: Forecast. 24 MR. SNELSON: And is this a weather normal 25 forecast? 26 MR. ROGERS: Yes. You are not surprised by 27 the look of that curve, are you? 28 MR. SNELSON: I'm not tremendously surprised. Les Services StenoTran Services Inc. 613-521-0703 2835 AMPCO PANEL 1, cr-ex (Rogers) 1 No. 2 MR. ROGERS: What you would expect is a fairly 3 flat curve over 240 hours when arrayed this way. 4 MR. SNELSON: I would expect that if there was 5 severe weather that you would see a larger upward 6 movement on the left hand side. 7 MR. ROGERS: This is normalized for abnormal 8 weather. 9 MR. SNELSON: That's why I asked the question 10 as to whether it was weather normal. 11 MR. ROGERS: So won't you agree with me that 12 this is exactly what you would expect to see for a low 13 duration curve normalized for January? 14 MR. SNELSON: Or in fairly normal weather 15 circumstance. Yes. 16 MR. ROGERS: All right. Thank you. Now, what 17 I want to do is look to see what the impact is of a 18 customer who can install a 50 megawatt generator behind 19 a meter. We calculated the values at the bottom of the 20 page. If you looked to the bottom left hand corner, 21 Option XVI, assuming full net load billing now. 22 MR. SNELSON: Yes. 23 MR. ROGERS: Do you agree that the customer 24 whose demand is shown in the figure who was able to run 25 a generator for a hundred hours and reduced his demand 26 by 50 megawatts would pay a bill of $148,500 in network 27 charges under Option XVI? 28 MR. SNELSON: I will accept those numbers. I Les Services StenoTran Services Inc. 613-521-0703 2836 AMPCO PANEL 1, cr-ex (Rogers) 1 checked them for order of magnitude. I didn't actually 2 do the calculations. 3 MR. ROGERS: All right. So we are close 4 anyway. You agree with that. 5 MR. SNELSON: Yes. 6 MR. ROGERS: And if we look over to the right 7 hand side under Option XVIII with full net load billing 8 once again assumed to make these comparable, that same 9 customer would pay $234,600 under my client's proposal. 10 MR. SNELSON: Yes. 11 MR. ROGERS: So there's quite a substantial 12 shift in the cost for a customer who is able to install 13 a generator behind a meter and one who is not. 14 MR. SNELSON: A customer who installed the 15 generator behind the meter and operates it during the 16 peak hours of the month gets some credit for reducing 17 the peak load of the system. 18 MR. ROGERS: Right. And that comes about by 19 virtue of the choice of the charge determinant. 20 MR. SNELSON: That is correct. 21 MR. ROGERS: Now, if we turn the page to 22 Exhibit N5, I want to just look to see what would happen 23 to another customer who does not have cogeneration 24 behind the meter. 25 Now the figure is set up in exactly the same 26 way with a couple of differences which I will explain to 27 you. 28 One is that the customer depicted in this Les Services StenoTran Services Inc. 613-521-0703 2837 AMPCO PANEL 1, cr-ex (Rogers) 1 figure does not have embedded generation. Another 2 difference is that although this customer takes the same 3 amount of energy as the customer in the earlier figure, 4 this customer has reduced his demand during the last 5 100 hours of the 240 hours of January. 6 Do you follow the assumptions? 7 MR. SNELSON: I follow the assumptions, yes. 8 MR. ROGERS: So we shifted that. The 9 reduction in demand is over the last 100 hours instead 10 of the first 100 hours, as was the case with the person 11 with the cogeneration, behind the meter in Figure N4. 12 Now, in each case, we are still looking at the 13 same peak hour period of 240 hours of the month, which 14 is a relatively flat duration curve as we can see. 15 Right? 16 MR. SNELSON: It's relatively flat in the 17 middle. There is significant upward movement on the 18 left-hand side for a very short period of time. 19 MR. ROGERS: Yes. There is a little bit of a 20 peak there, I agree. But, by and large, over the 21 240 hours or so it is a relatively flat curve. Wouldn't 22 you agree? 23 MR. SNELSON: It is a flat curve in the 24 middle, but I think the significance of the higher part 25 on the left-hand side should not be forgotten. 26 MR. ROGERS: All right. That's fine. We 27 won't forget. 28 Now, would you agree that under this scenario, Les Services StenoTran Services Inc. 613-521-0703 2838 AMPCO PANEL 1, cr-ex (Rogers) 1 if you look once again at the costs that are generated 2 by this type of a load, this load customer would pay 3 $297,000 under Option XVI, assuming full net load 4 billing? It would have to be full net load billing 5 because he doesn't have any cogeneration. Right? 6 MR. SNELSON: That's correct, yes. 7 MR. ROGERS: Under my client's proposal he 8 would pay $276,000. 9 MR. SNELSON: Yes. The difference is because 10 of the difference in the network rate between the two 11 proposals. 12 MR. ROGERS: Now, don't you therefore agree 13 that the load customer such as that indicated in 14 Figure N5, without any embedded generation, would pay 15 higher charges under Option XVI than he would under 16 Option XVIII? 17 MR. SNELSON: He would, and I believe that is 18 appropriate. 19 MR. ROGERS: Whereas the customer in 20 Figure N4, that is the one with embedded generation, 21 would pay about 50 per cent of the charges he would have 22 paid under Option XVIII, my client's proposal? 23 MR. SNELSON: And 50 per cent is a ratio 24 $148,000 to $234,000? 25 MR. ROGERS: Yes. 26 MR. SNELSON: Yes. 27 MR. ROGERS: So that even though these two 28 customers in these two figures have the same peak demand Les Services StenoTran Services Inc. 613-521-0703 2839 AMPCO PANEL 1, cr-ex (Rogers) 1 and the same energy consumption during the peak hours of 2 the month as we have defined them here, the customer in 3 Figure N4 pays $148,500 while the customer in N5, for 4 the same amount of energy, pays $297,000 under 5 Option XVI. 6 MR. SNELSON: Yes. It is appropriate because 7 the need for new system facilities is driven by 8 relatively few hours in the month. They may or may not 9 show up even on the load duration curve of a typical 10 weather corrected month. The need for system expansion 11 tends to be driven by a few cold days in winter and a 12 few hot days in the summer 13 The customer who is putting the 50 megawatts 14 of generation, if he really does operate it so as to 15 operate in the highest load hours of the month, can 16 virtually be guaranteed to be off the system or down to 17 his 50 megawatt level at the time of system peak, 18 whereas the other customer is taking 100 megawatts at 19 the time of the system peak. 20 MR. ROGERS: Are you finished there? 21 MR. SNELSON: Yes. 22 MR. ROGERS: Suppose the Board had some 23 concerns about free ridership and gaming whereby some 24 customers contributed less towards the fixed joint use 25 embedded infrastructure charges compared to other 26 customers, primarily as a result of the rate option that 27 is selected. Doesn't this set of examples just show the 28 opportunity for gaming that your proposal builds in? Les Services StenoTran Services Inc. 613-521-0703 2840 AMPCO PANEL 1, cr-ex (Rogers) 1 MR. SNELSON: No. I think I just said that I 2 believe this is an appropriate shift of costs given the 3 behaviour of the customers and I would not call that 4 gaming. 5 MR. ROGERS: If we look at this system 6 duration curve here, why 50 hours? Why have you chosen 7 50 hours as your charge determinant parameter? 8 MR. SNELSON: We have chosen -- well, first of 9 all maybe I should explain how it arose, because I think 10 it is being referred as Ontario Hydro Networks 11 Corporation's proposal and certainly that is where it 12 first surfaced in writing I believe. 13 But, unless I am mistaken, the proposal arose 14 from a telephone call during the -- a conference call 15 during the consultation process where some of these 16 matters were discussed. I did suggest that a 50 hour 17 number be looked at. 18 MR. ROGERS: It was AMPCO's proposal, 19 wasn't it? 20 MR. SNELSON: It was AMPCO's proposal in the 21 evidence, but it actually surfaced in your documents 22 before AMPCO's evidence was written. 23 MR. ROGERS: Well, I guess there are 24 18 options, but you are advocating before this Board on 25 behalf of AMPCO that they should endorse a 50 hour peak 26 period. 27 MR. SNELSON: That's correct. 28 MR. ROGERS: I would like to know why, having Les Services StenoTran Services Inc. 613-521-0703 2841 AMPCO PANEL 1, cr-ex (Rogers) 1 regard to this system duration period we are looking at. 2 MR. SNELSON: Well, I think that the important 3 thing here is that we have a coincident peak charge 4 determinant. It is important that the hours that are 5 within charge determinant are large enough to capture 6 the hours that will drive the need for system expansion. 7 As I have indicated, that is primarily the 8 hours between the little uptick on the left hand side of 9 the duration curve and the higher levels that would be 10 experienced on a month of perhaps extreme weather. You 11 also have to take into account that when it comes to 12 transmission, transmission losses, and heating and other 13 phenomena tend not to be linear phenomena and so a 14 10 per cent increase in load is more than a 10 per cent 15 increase in the severity on the system. 16 So the first thing I think is that the 17 important thing is that the charge determinant capture 18 the hours during which the need for system expansion is 19 driven. That really says that you could have quite a 20 short charge determinant for that purpose. 21 The movement from a one hour proposal of 22 alternative IV, which is what AMPCO proposed and talked 23 about during the consultation process, was partly in 24 response to concerns that there might be unreasonable 25 gaming of the system, that somebody who had gone off the 26 system for one hour might not in fact be significantly 27 reducing the needs of the system, that there might be 28 some other hour that actually also has some impact. Les Services StenoTran Services Inc. 613-521-0703 2842 AMPCO PANEL 1, cr-ex (Rogers) 1 So we proposed a broadening of it to 50 hours, 2 which we felt was enough to eliminate the possibility of 3 unproductive gaming. And so we chose that number. 4 It could have been a larger number, it could 5 have been a smaller number, but we think it is large 6 enough to capture the peak hours and not to encourage 7 unproductive gaming. 8 If you make it even larger, then there would 9 be many hours during the month when you would be 10 restricting the opportunity of somebody who has the 11 capability to use power off the times that matter from 12 doing so at relatively low cost. 13 MR. ROGERS: Is the peak hour usually between 14 11:00 and 12 o'clock on a weekday, summertime? 15 MR. SNELSON: Certainly in summertime it tends 16 to be driven by air conditioning loads and I believe it 17 tends to be towards the middle of the day. Whether it 18 is 11:00 to 12:00 or 2 o'clock, I don't know. 19 MR. ROGERS: So it is fairly predictable, 20 though, isn't it, as to where it will fall in the 21 summertime during the week? 22 MR. SNELSON: As the load pattern is now, yes. 23 MR. ROGERS: That would account for about 24 20 hours or so during the weekdays in the summertime 25 that are predictable? 26 MR. SNELSON: I am not so sure that there are 27 not hours on a really hot day that the load may be 28 higher than 50 hours, but to get captured might include Les Services StenoTran Services Inc. 613-521-0703 2843 AMPCO PANEL 1, cr-ex (Rogers) 1 quite a lot more than just those hours on the really hot 2 day and they might include quite a lot fewer hours, they 3 might not include any hours on a day when the 4 temperature is relatively moderate. 5 MR. ROGERS: Well, don't you agree though -- 6 maybe you don't -- that it is relatively predictable 7 that during the summertime the peak will occur about 8 midday when all the business are operating, the sun is 9 high in the air and it is hottest. 10 MR. SNELSON: It is quite predictable in the 11 summer that on a very hot day high loads will be 12 experienced and they will tend to be during the middle 13 of the day. 14 MR. ROGERS: All right. Now, isn't it also 15 true that in the wintertime the peak usually occurs 16 around 7:00 or so in the evening? 17 MR. SNELSON: Late afternoon, early evening. 18 There is lot of evidence around that shows 19 that the peaks during the winter are, I believe, 20 somewhat flatter than during the summer and that load 21 tends to be higher for a longer period of time. But if 22 there is a higher period peak it is sort of late 23 afternoon, early evening and, again, it tends to be 24 highest on the very cold days when the system is under 25 stress. 26 MR. ROGERS: Right. And during the week when 27 businesses are operating, if -- 28 MR. SNELSON: And when businesses are Les Services StenoTran Services Inc. 613-521-0703 2844 AMPCO PANEL 1, cr-ex (Rogers) 1 operating, yes. 2 MR. ROGERS: it's not certain, I agree with 3 that, but there are about 20 working days in a month and 4 I am suggesting to you, then, that it is relatively easy 5 to predict when about 40 of those peak hours are going 6 to occur. 7 MR. SNELSON: And I disagree with that. 8 MR. ROGERS: Of course, to the extent that one 9 can predict when the people occur, it encourages gaming, 10 doesn't it? 11 MR. SNELSON: To the extent that you can 12 predict when the peak will occur, it encourages people 13 to move their consumption. If that moving of 14 consumption removes their loads from the times when the 15 system is under stress, then I would not call that 16 gaming. 17 MR. ROGERS: Is there not still a concern 18 about free ridership, even if you disagree with the 19 gaming problem? 20 MR. SNELSON: There could be a concern about 21 free ridership in that equity consideration rather than 22 a strictly cost causality or an economic efficiency 23 consideration. 24 MR. ROGERS: All right. Fair enough. You 25 would agree that the principle of cost allocation and 26 rate design is there should be to the extent possible 27 acceptance of the proposals by the customers of the 28 utility. Les Services StenoTran Services Inc. 613-521-0703 2845 AMPCO PANEL 1, cr-ex (Rogers) 1 MR. SNELSON: That's often put forward as an 2 important principle. Yes. 3 MR. ROGERS: And many customers object to this 4 concept of free ridership, don't they? 5 MR. SNELSON: That's why I said that equity is 6 an important consideration. 7 MR. ROGERS: All right. That's fair enough, 8 Mr. Snelson. Thank you. 9 Now, I'm not going to deal with the diagrams 10 any more, you will be glad to know, but I do have a few 11 general questions for you. 12 AMPCO is an organization which is an advocate 13 on behalf of large electricity users. Would you agree 14 with that? 15 MR. SNELSON: We certainly represent the 16 interest of the larger electricity users in dealings 17 with respect to electricity and electricity regulation. 18 Yes. 19 MR. ROGERS: And you have presented to us 20 quite a detailed proposal on behalf of AMPCO in 21 Exhibit H2.1. 22 MR. SNELSON: That is correct. 23 MR. ROGERS: You made the point a number of 24 times, Mr. Snelson, that these recommendations are only 25 acceptable, I think is the terminology you had used, to 26 AMPCO providing they are all accepted. 27 MR. SNELSON: We have indicated some key 28 linkages in our recommendations. Les Services StenoTran Services Inc. 613-521-0703 2846 AMPCO PANEL 1, cr-ex (Rogers) 1 MR. ROGERS: Perhaps I have overstated it. 2 What I need to know is these clear key linkages. 3 MR. SNELSON: Yes. 4 MR. ROGERS: What proposal is the linchpin? 5 If the Board doesn't agree with you on one proposal, 6 then are they to ignore all your other recommendations? 7 MR. SNELSON: No. 8 MR. ROGERS: How about, for example, suppose 9 the Board accepts my client's proposal for net load 10 billing, do all of your other proposals still stand as 11 AMPCO's recommendation or are they withdrawn? 12 MR. SNELSON: Your proposal being a 50 per 13 cent -- with 50 per cent of embedded generation added 14 back into the network charge determinant. 15 MR. ROGERS: Yes. Generally speaking. It's a 16 little more complex than that, but that's the major 17 component of it. 18 MR. SNELSON: Yes. I believe that many of the 19 other recommendations would still stand in that case. 20 MR. ROGERS: I don't know whether the Board is 21 having trouble with this, but I am. Can you provide us 22 with a little bit of a guide now as to what proposals 23 are inextricably linked together in your proposal? 24 MR. SNELSON: Well, I will give you two -- I 25 can give you a number of clear linkages. 26 MR. ROGERS: All right. By this I mean now 27 it's a package deal so far as AMPCO is concerned. If 28 the Board doesn't go for the package, piecemeal is not Les Services StenoTran Services Inc. 613-521-0703 2847 AMPCO PANEL 1, cr-ex (Rogers) 1 acceptable. 2 MR. SNELSON: And I am giving some clear 3 linkages. 4 MR. ROGERS: All right. Thank you. 5 MR. SNELSON: With respect to transmission 6 customer, we have proposed as our primary proposal that 7 embedded wholesale market participants can be 8 transmission customers. I don't believe that that 9 recommendation specifically works without having a 10 coincident peak charge determinant for network. 11 I do believe that the alternative which we 12 have accepted and put forward through the settlement 13 process of having the transmission customers defined by 14 the entering of meters and with the proviso that charges 15 are passed on with as little distortion as possible, I 16 believe that proposal works with either non-coincident 17 or coincident peak charges. It works better with 18 coincident peak charges. 19 The proposal as a -- the proposal to accept, 20 reluctantly accept, gross load billing on connections is 21 dependent upon the adoption of the narrow definition of 22 line connection. If the narrow definition of line 23 connection were not accepted, then we would want to go 24 to some other way of determining an appropriate amount 25 for the customers to continue to pay to cover off -- to 26 prevent the transfer of costs to other customers for 27 assets that are solely used by the customer who is 28 reducing his load. Les Services StenoTran Services Inc. 613-521-0703 2848 AMPCO PANEL 1, cr-ex (Rogers) 1 MR. ROGERS: What do you propose because I can 2 tell you right now I am going to urge the Board to, with 3 respect, reject your narrow definition of line 4 connections. If I succeed in that, what do you propose 5 the Board do? 6 MR. SNELSON: I don't believe that we have put 7 forward and decided upon, that AMPCO has decided upon -- 8 I'm not in a position to make policy for AMPCO right 9 here and now. AMPCO has not decided upon precisely what 10 its recommendation would be in that circumstance. 11 It's something which, if they wish to, they 12 can put forward a position as an alternative during 13 final argument. 14 MR. ROGERS: I appreciate you are at a bit of 15 a disadvantage because you can't speak policy, but you 16 are largely the author of this report, I think, aren't 17 you? 18 MR. SNELSON: I'm largely the author of the 19 report, but it has been done in conjunction with a 20 number of AMPCO committees, AMPCO members and Board of 21 Directors. 22 MR. ROGERS: All right. 23 MR. SNELSON: So it's not -- I may have pushed 24 the pen for a lot of it, I may have had some input, and 25 I did have some input on some of the discussions, but I 26 was not the sole decision-maker upon it. 27 MR. ROGERS: So some of the policy decisions 28 which you are recommending to this Board are the result Les Services StenoTran Services Inc. 613-521-0703 2849 AMPCO PANEL 1, cr-ex (Rogers) 1 of a policy decision by AMPCO and not yourself. 2 MR. SNELSON: That is correct. 3 MR. ROGERS: I see. All right. Just help me, 4 would you. Are there any other key linkages that we 5 should be aware of? 6 MR. SNELSON: I have mentioned the rolling 7 together of the line connection and the transformation 8 pool. If that were to be done, then definitely we would 9 not recommend that that be done if the buy-out provision 10 or some similar provision was not to be put into place. 11 Our recommendation in that case would be to keep the 12 pools separate. 13 MR. ROGERS: Is that the key linked issues 14 then? 15 MR. SNELSON: Those are the main ones. Yes. 16 MR. ROGERS: Thank you. Let's talk about this 17 buy-out for a moment. You mentioned it a minute ago. 18 It's important to AMPCO that the Board permit customers 19 to buy line connections at net book value. That's a key 20 part of your package, isn't it? 21 MR. SNELSON: Yes, it is. 22 MR. ROGERS: And this would be at the 23 individual customers option. Either it could or could 24 not at its option, depending on the economics, buy the 25 line connection. 26 MR. SNELSON: That is correct. 27 MR. ROGERS: Now, you would agree that the net 28 book value of an asset will have been reduced over the Les Services StenoTran Services Inc. 613-521-0703 2850 AMPCO PANEL 1, cr-ex (Rogers) 1 years by the application of depreciation. 2 MR. SNELSON: Yes. 3 MR. ROGERS: And depending on which asset we 4 are talking about, but that depreciation would have been 5 funded by many customers who use that facility. 6 MR. SNELSON: It would have been funded 7 through the revenue requirement. Yes. 8 MR. ROGERS: Right. Why then would it be fair 9 to allow one customer to buy an asset at net book value 10 which might be much lower than its true economic value 11 because of depreciation paid by other customers? 12 MR. SNELSON: We look at it slightly 13 differently, that if the transfer were to take place, 14 the higher the net book value, then that is an increase 15 in the value for OHNC and their only expectation is that 16 they will recover a normal return on their net book 17 value, not upon some higher value that might be decided 18 upon by some other method. 19 MR. ROGERS: But if OHNC sold these assets, it 20 would enure to the benefit of all of its customers who 21 have paid the depreciation. 22 MR. SNELSON: Including the customer who is 23 buying the asset and the customer who is buying it may 24 have paid a large part of that himself. 25 MR. ROGERS: True, but he has a choice. He 26 won't buy this asset unless it's to his economic 27 advantage to do so, whatever the price. Right? 28 MR. SNELSON: That's correct. Les Services StenoTran Services Inc. 613-521-0703 2851 AMPCO PANEL 1, cr-ex (Rogers) 1 MR. ROGERS: So if OHNC were to charge a 2 minimum of net book value, but more than net book value 3 if the economic value was there, isn't that the 4 appropriate way to deal with it? 5 MR. SNELSON: Our concern is how would you 6 determine the economic value? You certainly can't 7 determine a market value given the limitations of the 8 market. There may be other means of determining a fair 9 price. 10 MR. ROGERS: You and Mr. Mark had this 11 discussion I recall about market value on this very 12 issue. I don't want to go over that again. 13 If I could suggest a way to value that asset 14 such that its true economic worth to the customer buying 15 it was affected, then you would agree that that would be 16 the appropriate to go. 17 MR. SNELSON: I don't know quite what method 18 you are going to suggest or what kind of a hypothetical 19 question. 20 MR. ROGERS: What difference does it make as 21 long as the true value of that asset is imposed upon it, 22 such that the customer buying it still wants to buy? It 23 is in his economic benefit to do so and it is higher 24 than net book value so that all of the other customers 25 of my client benefit. Isn't that the appropriate 26 treatment? 27 MR. SNELSON: I'm not sure what happens in 28 your scenario to the purchase price in excess of net Les Services StenoTran Services Inc. 613-521-0703 2852 AMPCO PANEL 1, cr-ex (Rogers) 1 book value. Does the purchase price in net book value 2 go to increased profits to OHNC? 3 MR. ROGERS: Suppose it went to reduced costs 4 for all of the other customers who paid the 5 depreciation, it was somehow a credit back to the 6 depreciation account, let's say, or some other 7 technique, that would be the fair way to do it, wouldn't 8 it? 9 MR. SNELSON: That would certainly avoid the 10 concern about OHNC profiting from the sale of these 11 assets. 12 MR. ROGERS: And that would satisfy AMPCO's 13 Robin Hood's spirit about OHNC getting this windfall, 14 would it? 15 MR. SNELSON: I'm not sure quite where Robin 16 Hood's spirit applies. 17 MR. ROGERS: Would my proposal be acceptable 18 to AMPCO? 19 MR. SNELSON: Can you repeat your proposal 20 because it was some time ago and I have forgotten the 21 specifics of it? 22 MR. ROGERS: Yes. If a customer wanted to buy 23 these assets it would pay a price that was no lower than 24 net book value and hopefully a price that would reflect 25 the actual economic value of that asset at the time. 26 MR. SNELSON: Your proposal is the customer 27 would do that and the question is whether that would be 28 acceptable to AMPCO? Les Services StenoTran Services Inc. 613-521-0703 2853 AMPCO PANEL 1, cr-ex (Rogers) 1 MR. ROGERS: Yes. 2 MR. SNELSON: Again, I'm in the situation that 3 AMPCO has not specifically discussed that. I know that 4 there are, as an expert, some knowledge in these areas, 5 but there are other ways of determining value than net 6 book value. 7 MR. ROGERS: All right. 8 Maybe it is unfair to ask you whether AMPCO 9 will accept it. But don't you, Mr. Snelson, agree that 10 that would be a fair way to deal with it, the problem? 11 MR. SNELSON: You have given a general 12 description of determining a fair book value and you 13 haven't told me how you are going to determine the fair 14 value, so I find that a hard question to answer. 15 Fairness, like beauty, is in the eye of the beholder. 16 MR. ROGERS: I won't belabour the point. I 17 think the Board understands the point. 18 I think those are my questions. Thank you 19 very much, Mr. Snelson. 20 Thank you, sir. 21 MEMBER SMITH: Maybe you can help me out on 22 the value of the assets. 23 Net book value is always lower than the 24 perceived other value, meaning -- you are going back and 25 forth between these two values. One is the net book 26 value, and that is the value you can establish. It 27 exists somewhere. 28 Is it your assumption that if somehow the true Les Services StenoTran Services Inc. 613-521-0703 2854 AMPCO PANEL 1 1 value, which turned out to be different than the net 2 book value, could be established by some magic formula 3 it would always be the higher of the two? 4 MR. SNELSON: This is a question to me or a 5 question to -- 6 MEMBER SMITH: No, no, I have to ask you. 7 MR. SNELSON: Okay. I believe the net book 8 value can be higher or lower than some other means of 9 determining the value. For instance, if you had a very 10 expensive piece of equipment that perhaps had been put 11 in in an expectation of a very large load that never 12 materialized, then the actual economic worth of that 13 asset could be less than net book value. At the same 14 time, you have situations where assets were put in 15 perhaps many years ago when costs were lower and net 16 book value might be less than some estimate of economic 17 value as estimated today. 18 MEMBER SMITH: But it is your guess that most 19 of the time it would be the other way around, I take it, 20 and that is why you would want net book value 21 established as a policy? 22 MR. SNELSON: I would expect that of those two 23 circumstances the latter is probably the more prevalent. 24 MEMBER SMITH: In that case, can you help me 25 out with something I'm not very familiar with? Was that 26 a convention in the way the accounting was done to, in a 27 sense, depreciate the asset faster than its value was 28 depreciating? Was this a conscious decision taken in Les Services StenoTran Services Inc. 613-521-0703 2855 AMPCO PANEL 1 1 the old days? 2 MR. SNELSON: No, I don't believe so. In 3 actual fact, I was a member of the depreciation review 4 committee of Ontario Hydro in a previous existence, and 5 Ontario Hydro's policies for depreciation were to 6 depreciate assets on a straightline basis over their 7 estimated physical life. They did not adopt accelerated 8 depreciation based on some shorter financial life that 9 was shorter than the estimated physical life. 10 The reason why net book value today perhaps 11 tends to be less than some other estimate of value, it 12 tends to be one of inflation and the depreciated value 13 is based on the original cost rather than replacement 14 cost. 15 MEMBER SMITH: Just another quick one. Can 16 you explain to me the difference between "gaming" and 17 "free ridership"? 18 MR. SNELSON: In the context of the charge 19 determinant, the session that we just had, then gaming I 20 believe refers very specifically to making some change 21 to your operating pattern to reduce your charges in a 22 way that doesn't provide a comparable benefit to the 23 system. So if you are just reducing your demand for one 24 or two hours and the system demand is high enough for 10 25 or 15 hours, really those 10 or 15 hours drive the need 26 for new capacity. Reducing your demand for one or two 27 hours hasn't actually done anything to reduce that, but 28 you have reduced your charges. I consider that to be Les Services StenoTran Services Inc. 613-521-0703 2856 AMPCO PANEL 1 1 gaming. 2 MEMBER SMITH: Okay. 3 MR. SNELSON: Free ridership is more, in my 4 mind anyway, of a perception, for instance, the 5 perception of equity with respect to export and 6 wheel-through charges. I believe that the reason that 7 people are talking about the $1 a megawatt hour minimum 8 for EWT charges is because without it there is a 9 perception that there is free ridership, that the 10 customers in the absence of congestion may be able to -- 11 generators may be able to schedule export transactions 12 and pay nothing towards the transmission system. 13 So to me that is a proposal to try and reduce 14 free ridership. 15 Now, some people may perceive free ridership 16 with a coincident peak charge determinant, even with the 17 50 hours, that somebody who manages to put most of their 18 usage outside those 50 hours could end up paying 19 relatively little towards the transmission system, and 20 there may be some need for equity concerns, to consider 21 some form of payment to avoid that perception of free 22 ridership. 23 MEMBER SMITH: Okay. Thank you. 24 MEMBER VLAHOS: Mr. Snelson, I would invite 25 you to read the transcript of today and see if there was 26 anything else, any other links, that you had in mind 27 that may be in your prefiled evidence but have not been 28 outlined today. Could you do that? Les Services StenoTran Services Inc. 613-521-0703 2857 AMPCO PANEL 1 1 MR. SNELSON: Yes. 2 MEMBER VLAHOS: Perhaps maybe we can give that 3 an undertaking number. If there is anything else that 4 you want to complete -- I know you had to think quickly, 5 on the go -- 6 MR. SNELSON: That's right. 7 MEMBER VLAHOS: -- about all the links and it 8 would assist the Board if we had a complete list of 9 those links. Now, I know you discussed them in some 10 fashion in your prefiled evidence, but over the course 11 of the hearing there may be some links that have become 12 important and others less so. Could you undertake to do 13 that, to confirm whether the links that you spoke of 14 today is the complete list or if you wish to add some 15 more? 16 MR. FISHER: Excuse me for interrupting, 17 Mr. Vlahos. If it is of any assistance, we planned on 18 speaking about the various ramifications and links in 19 our final argument. 20 MEMBER VLAHOS: I appreciate that and that 21 will be helpful, but it may help us turn our minds to 22 those things until such time as five weeks later. 23 MR. LYLE: We will mark that as 24 Undertaking F14.4. 25 UNDERTAKING NO. F14.4: Mr. Snelson 26 undertakes to review today's transcript 27 and determine whether there were any 28 other links which were not in his Les Services StenoTran Services Inc. 613-521-0703 2858 AMPCO PANEL 1 1 prefiled evidence nor outlined today 2 THE PRESIDING MEMBER: Thank you. 3 I just have one question, Mr. Snelson. 4 You said earlier, and this is twice you said 5 this now on the record, that the company has paid for 6 its line connection, meaning that the company has paid a 7 contribution or the company has paid for the cost of the 8 assets? I guess it is like you say, it is in the eyes 9 of the beholder. 10 MR. SNELSON: And the questions is: Which of 11 those was I referring to? 12 THE PRESIDING MEMBER: Yes. 13 MR. SNELSON: I believe it was probably both 14 instances. There certainly have been requirements for 15 customers to make certain contributions and there have 16 been requirements for customers to pay the cost of 17 specific pieces of line. For instance, I believe that 18 INCO has shown in their interrogatory responses some 19 specific lines that they were required to pay for. 20 So I believe there is both circumstances. 21 THE PRESIDING MEMBER: Now, in terms of how do 22 we go on a going forward basis, a company that has paid 23 the contribution under the policies of OHNC doesn't have 24 any right to hook-up? Is that correct? Do you disagree 25 with that? 26 MR. SNELSON: Rights to that particular line? 27 THE PRESIDING MEMBER: Yes. 28 MR. SNELSON: They certainly don't have Les Services StenoTran Services Inc. 613-521-0703 2859 AMPCO PANEL 1 1 exclusive rights to that particular line if they have 2 only contributed to it. Under the buy-out proposal, 3 then I believe what we have determined from some 4 discussion to the interrogatories, and so on, is that 5 the capital contributions would have been used to offset 6 the book value of that line and that the line would then 7 be recorded in the books at the net, after the capital 8 contribution. 9 So the customer, if he was to buy that net, 10 would not be -- would effectively be getting the credit 11 for the part he has already paid. He certainly wouldn't 12 be paying for it twice. 13 THE PRESIDING MEMBER: If the company has 14 actually paid for, in whole or in part, the actual 15 asset, there is a distinction there financially. 16 MR. SNELSON: Well, if he has paid the whole 17 of the cost of the asset, then -- 18 THE PRESIDING MEMBER: That's clear. 19 MR. SNELSON: It's clear. If he has paid a 20 part of it, then it is the remaining part that he would 21 have to pay to buy that out. 22 THE PRESIDING MEMBER: Based on -- 23 MR. SNELSON: Based on the remaining net book 24 value after accounting for the amounts already paid. 25 THE PRESIDING MEMBER: Okay. I think I 26 understand now exactly. So thank you. 27 Mr. Fisher, do you have some redirect? 28 MR. FISHER: I have none, thank you. Les Services StenoTran Services Inc. 613-521-0703 2860 AMPCO PANEL 1 1 THE PRESIDING MEMBER: Thank you very much, 2 Mr. Snelson. 3 Where do we go now next? Mr. Lyle. 4 MR. LYLE: I understand that tomorrow morning 5 OHNC's panel will be coming back to address 6 implementation. 7 MR. ROGERS: I thought I would call in the 8 morning Dr. Poray and he can address the EWT charge 9 summary which I have filed and as well Mr. Curtis will 10 be here with him to discuss -- the two of them will 11 discuss implementation. 12 THE PRESIDING MEMBER: Thank you. 13 Then the question is if the Board has any 14 questions, Mr. Campbell, of all the material you filed, 15 can you make -- I think it you would be -- 16 MR. CAMPBELL: Mr. Boland? 17 THE PRESIDING MEMBER: Yes. Bruce Boland. 18 MR. CAMPBELL: Mr. Boland's availability, if I 19 recall quickly, if you wanted him back, first thing 20 Thursday morning I think would be his preference. It 21 might be possible to get him in tomorrow afternoon. 22 THE PRESIDING MEMBER: Very well, I think 23 rather than coming for such a short while, have him come 24 on Thursday. 25 So he will come on Thursday then if we need 26 him. We will have had time by then to determine whether 27 we do. We will also have heard Dr. Poray's discussion 28 on the EWT transaction. Les Services StenoTran Services Inc. 613-521-0703 2861 1 MR. CAMPBELL: Yes. 2 THE PRESIDING MEMBER: Okay. 3 MR. ROGERS: Thank you. I think then we are 4 out of evidence today, I believe. 5 MR. LYLE: Yes, I believe so. 6 THE PRESIDING MEMBER: So we will see 7 everybody the at 9 o'clock tomorrow. 8 Thank you. 9 --- Whereupon the hearing adjourned at 1625, to resume 10 on Tuesday, March 7, 2000 at 0900 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 Les Services StenoTran Services Inc. 613-521-0703 2862 1 INDEX OF PROCEEDING 2 PAGE 3 Upon resuming at 0932 2662 4 Preliminary Matters 2662 5 6 ENERGYLINK PANEL 1 7 SWORN: HAROLD WONG 2663 8 Evidence-in-chief 2663 9 Cross-Examination by Mr. Adams 2682 10 Cross-Examination by Mr. Campbell 2690 11 Cross-Examination by Ms Friedman 2700 12 Examination by Board Counsel 2702 13 Cross-Examination by Mr. Rogers 2704 14 Questions by the Board 2708 15 Upon recessing at 1102 2713 16 Upon resuming at 1123 2713 17 18 TRANSALTA PANEL 1 19 SWORN: WAYNE TAYLOR 2713 20 SWORN: STEPHEN HODGKINSON 2713 21 Examination-in-Chief by Mr. Budd 2714 22 Cross-Examination by Mr. Adams 2730 23 Cross-Examination by Ms Friedman 2736 24 Cross-Examination by Mr. Campbell 2738 25 Examination by Board Counsel 2740 26 Cross-Examination by Mr. Rogers 2744 27 Questions by the Board 2765 28 Further Cross-Examination by Mr. Rogers 2776 Les Services StenoTran Services Inc. 613-521-0703 2863 1 INDEX OF PROCEEDING (Cont'd) 2 PAGE 3 Upon recessing at 1259 2777 4 Upon resuming at 1406 2777 5 6 POLLUTION PROBE PANEL 1 7 SWORN: JACK GIBBONS 2779 8 Examination-in-chief by Mr. Klippenstein 2779 9 Cross-Examination by Mr. Cowan 2784 10 Cross-Examination by Mr. Campbell 2786 11 Examination by Board Counsel 2798 12 Cross-Examination by Mr. Rogers 2801 13 Questions by the Board 2807 14 Upon recessing at 1458 2810 15 Upon resuming at 1522 2810 16 17 AMPCO PANEL 1 18 PREVIOUSLY SWORN: KENNETH SNELSON 2811 19 Continued Cross-Examination by Mr. Rogers 2811 20 Questions by the Board 2853 21 Upon adjourning at 1625 2861 22 23 24 25 26 27 28 Les Services StenoTran Services Inc. 613-521-0703 2864 1 EXHIBITS 2 NO. PAGE 3 G14.1 Covering letter, dated 2663 4 February 23, 2000, with 5 Table 5B, Table 5C and 6 curriculum vitae of Harold 7 Wong attached 8 9 G14.2 Curriculum vitaes of Wayne 2713 10 Taylor and Stephen Hodgkinson 11 12 G14.3 Document entitled 2778 13 "Implementation of Transmission 14 Rates" 15 16 G14.4 Curriculum Vitae of Jack 2779 17 Gibbons, Pollution Probe 18 19 G14.5 Document entitled "Pollution 2798 20 Loopholes" dated February 2000, 21 authored by Mr. Jack Gibbons 22 23 24 25 26 27 28 Les Services StenoTran Services Inc. 613-521-0703 2865 1 UNDERTAKINGS 2 NO. PAGE 3 F14.1 Mr. Taylor to undertake to 2750 4 provide the average load 5 growth and the generation 6 that has been added, for the 7 period 1990 to date, on a 8 year-by-year basis 9 F14.2 Mr. Hodgkinson undertakes to 2774 10 advise typical gas intake for 11 a 100 megawatt plant 12 F14.3 Undertaking by Mr. Taylor to 2777 13 File Comparable Liability 14 Clause to that of OHNC 15 F14.4 Mr. Snelson undertakes to 2857 16 review today's transcript and 17 determine whether there were 18 any other links which were not 19 in his prefiled evidence nor 20 outlined today