1 1 EB-2000-0317 2 3 4 THE ONTARIO ENERGY BOARD 5 6 7 IN THE MATTER OF the Ontario Energy Board Act, 1998; 8 9 10 AND IN THE MATTER OF an Application by The Consumers Gas 11 Company Ltd., carrying on business as Enbridge Consumers 12 Gas, for an order or oders approving or fixing rates for 13 the sale, distribution, transmission and storage of gas 14 for its 2001 fiscal year. 15 16 17 18 19 Hearing held at: 20 2300 Yonge Street, 25th Floor, Hearing Room No. 1 21 Toronto, Ontario on Tuesday, November 28, 2000, 22 commencing at 0910 23 24 25 26 TECHNICAL CONFERENCE 27 28 2 1 APPEARANCES 2 COLIN SCHUCH/ Board Staff 3 HIMA DESAI 4 5 6 JERRY FARRELL/ Enbridge Consumers Gas 7 TOM LADANYI 8 ROBERT WARREN Consumers Association of Canada 9 TOM ADAMS Energy Probe 10 ED ROBERTSON Vulnerable Energy Consumers 11 Coalition 12 VALERIE YOUNG A.E. Sharpe Limited 13 TIBOR HAYNAL TransCanada Pipelines 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 3 1 Toronto, Ontario 2 --- Upon commencing on Tuesday, November 28, 2000 3 at 0910 4 MR. SCHUCH: Good morning, everyone, and 5 welcome to the Enbridge Consumers Gas Technical 6 Conference for the EB-2000-0317 proceeding to address 7 the gas cost increase this year. 8 My name is Colin Schuch and I am with Board 9 staff. For the record, Enbridge Consumers Gas has 10 applied to the Board for an order or orders approving or 11 fixing rates for the sale, distribution, transmission 12 and storage of natural gas to be effective for the 13 fiscal year commencing October 1, 2000. 14 The Board has assigned File No. RP-2000-0040 15 to this proceeding. 16 The application requested that interim rates 17 be approved by the Board to reflect expectations of gas 18 costs for fiscal 2001. The Board has established a 19 proceeding, EB-2000-0234, to deal with the request and 20 approved interim rates effective October 1, 2000. 21 In a letter dated November 15, 2000, the 22 company has come forward with a revised forecast of gas 23 costs and has requested that new interim rates be 24 approved by the Board effective Jan. 1, 2001. 25 The new interim rates would represent an 26 increase in the typical residential customer's bill of 27 approximately 10 per cent over the October 1 interim 28 rates. 4 1 The Board has assigned File No. EB-2000-0317 2 to this segment of the main rate proceeding. 3 The purpose of today's conference is for 4 intervenors and Board staff to seek clarification of the 5 pre-filed evidence of ECG on the issue of gas costs and 6 to increase intervenor and Board staff's understanding 7 of the evidence. 8 This conference will be followed by a 9 Settlement Conference today in which an effort will be 10 made for all parties to reach an agreement on the 11 issues. 12 There will be a transcript prepared for 13 today's proceeding and it will be available on the 14 Board's Web site tomorrow. A copy will also be 15 forwarded to all intervenors in the coming week. The 16 transcript will form part of the record of the 17 proceeding. 18 In terms of the order of questioning, my 19 suggestion is that intervenors lead off in order of 20 appearance and Board staff will conclude the 21 questioning. 22 Barring any objections, we will be providing a 23 live feed of this conference to the 24th, 25th and 26th 24 floors of this building to allow Board staff and members 25 of the Board an opportunity to monitor this proceeding. 26 I suggest that we commence and continue until 27 a 20-minute break, which I should call at or around 28 10:30, or whatever time suits us. 5 1 After the break, when we conclude the 2 questioning, we can commence the Settlement Conference. 3 Those parties wishing to participate will convene in 4 this hearing room for the Settlement Conference, which 5 we hope to conclude this afternoon. 6 The live audio feed will be cut off for the 7 Settlement Conference. 8 As noted in Procedural Order No. 1, which you 9 should all have, the Board will hear submissions on 10 issues surrounding the gas costs, if necessary, this 11 Thursday, November 30, commencing at 10:00 a.m. Parties 12 will be informed by fax, probably Wednesday afternoon, 13 informing as to whether the Board will be proceeding 14 with the hearing. 15 Those are my introductory remarks. 16 I think at this point we could have 17 appearances. Please introduce yourselves and state your 18 name for the court reporter, and please also state your 19 affiliation. 20 We will begin here to my right with the Board 21 staff. 22 MS DESAI: Hima Desai with Board staff. 23 MR. WARREN: Robert Warren for the Consumers 24 Association of Canada. 25 MR. FARRELL: Jerry Farrell for Enbridge 26 Consumers Gas. 27 MR. LADANYI: Tom Ladanyi from Enbridge 28 Consumers Gas. 6 1 MR. ADAMS: Tom Adams on behalf of Energy 2 Probe. 3 I wonder if there is an appropriate point to 4 make some submissions for late intervenor status? We 5 are not formally intervenors, but wish to provide 6 notice. 7 MR. SCHUCH: Sure, I would think so. 8 --- Pause 9 MR. SCHUCH: It will be done formally, will 10 it, Tom? 11 MS DESAI: Yes. 12 Tom, I think that should be done formally, 13 like through a letter to the Board Secretary. 14 MR. ADAMS: That's fine. 15 MS DESAI: That would be fine. 16 MR. ADAMS: We will provide it. 17 Our appearance here is notice to the parties 18 of our intention to intervene. If there are any 19 objections I could hear them now. 20 MR. FARRELL: No, we won't have any objections 21 as long as he accepts the record as it is when he 22 intervenes, and I think in the first Technical and 23 Settlement Conference in EB-2000-0234 there were a 24 couple of parties who are shown in the Settlement 25 Proposal as Intervenor status pending, and we are quite 26 happy to do the same for Energy Probe. 27 MR. ROBERTSON: I am Ed Robertson representing 28 VECC. 7 1 THE COURT REPORTER: I'm sorry, sir. Was that 2 Robinson? Robertson? 3 MR. ROBERTSON: Robertson. 4 THE COURT REPORTER: Thank you. 5 MS YOUNG: Valerie Young, A.E. Sharpe Limited. 6 MR. HAYNAL: Tibor Haynal, TransCanada 7 Pipelines. 8 --- Pause 9 MR. SCHUCH: I think that is everyone. 10 Well, I think now we could turn the proceeding 11 over to Enbridge, unless anybody has any other comments 12 they want to bring forward. 13 I turn it over to you. 14 MR. FARRELL: We have a panel of four people. 15 I hesitate to call them witnesses since this isn't a 16 hearing, and I will let each of them introduce 17 themselves by name and title and then each of them will 18 then explain their part in relation to the interim 19 application. 20 MS DUGUAY: My name is Pascale Duguay. I am 21 Manager, Rate, Research and Design. Basically I have 22 been responsible for the cost allocation and rate design 23 exhibits that have been filed in this proceeding. 24 MR. SMALL: Don Small. I am the Manager of 25 Gas Costs and Budgets and I am responsible for the 26 exhibits you will see in the P3, Tab 1 on the gas costs 27 themselves. 28 MR. BRENNAN: My name is Frank Brennan. I am 8 1 Director of Gas Supply Services. I am looking after the 2 gas cost section of this application. 3 MR. BOURKE: My name is Robert Burke. I am 4 Manager of Regulatory Accounting. I have provided 5 evidence at Exhibit P3, Tab 2, in the determination of 6 the cost consequences of this interim gas upstream. 7 MS DUGUAY: The first thing I would like to do 8 is to provide all parties with an overview of the 9 company's proposal in this application as it relates to 10 rate design. 11 The company is proposing to increase its rates 12 to better reflect market conditions and thereby 13 providing a better price signal to customers as it 14 relates to the commodity cost of gas. 15 This increase in rates would also act to 16 mitigate the balance that would otherwise be accumulated 17 in the 2001 purchase gas variance account or the PGVA. 18 The company is proposing that the upstream 19 rates be implemented and effected in the first billing 20 cycle of January 2001. The increment in the revenue 21 requirement resulting from the increase in gas costs 22 would be effective to changes in the gas supply and gas 23 supply load balancing charges appearing in the company's 24 rate schedule. 25 As seen at Exhibit P3, Tab 2, Schedule 1, Line 26 11, the total change in the revenue requirement stemming 27 from this gas cost increase amounts to $211.4 million. 28 From a rate design perspective, the company is 9 1 proposing to set rates such that they would recover an 2 additional amount of $206.8 million. The difference 3 between the $11.4 million, which is the total change in 4 the revenue requirement versus what we are proposing to 5 effect in rates, the 206.8 amounts to a $4.6 million 6 difference. This difference is attributable to unbilled 7 and unaccounted for gas, company use and lost and 8 unaccounted for gas. 9 The reason for discarding these increases 10 or -- let me rephrase that -- to defer that at this 11 stage is that these costs are either distribution or 12 storage and transmission related. So as a result of 13 that, the company proposes to defer the recovery of 14 these costs in the final rates that will be set in the 15 RP-2000-0040 proceeding. 16 Based on the company's application, the gas 17 supply charge would increase to 24.4 cents per cubic 18 metre from the level approved in the interim level of 19 20.8 cents per cubic metre that was approved as of 20 October 1, 2000. 21 The impact on the gas -- 22 MR. WARREN: I'm sorry to interrupt. Could 23 you just do those numbers again? I was a little slow on 24 hearing them. 25 MS DUGUAY: Okay. So basically the new gas 26 supply charge included in this application, provided 27 that it would be approved of course, would be 24.4 cents 28 per cubic metre. And in comparison, the interim rates 10 1 as of October 1, 2000, the gas supply charge at that 2 point was 20.8 cents per cubic metre. 3 MR. WARREN: Thank you. I'm sorry to 4 interrupt. 5 MS DUGUAY: No, that's fine. 6 So now the impact on the gas supply load 7 balancing charges do vary on a rate-class basis, but the 8 increase on average would represent an increment of 9 about 1.9 per cent. The company is proposing that the 10 2001 PGVA reference price be adopted to $282.617 per 11 10(3)m(3) effective January 1, 2001 from the level 12 supporting the interim rates, which was $245.412 per 13 10(3)m(3). 14 Finally, the company is not proposing to clear 15 the forecast December 31, 2000 PGVA balance of 16 $103 million at the time the rates are changed to 17 reflect this upstream gas cost change. Rather, the 18 company is proposing that the 2001 PGVA at fiscal year 19 end being the projected or actual balance at the end of 20 September 30, 2001, which is currently forecast to 21 amount to $88.1 million, be dealt with in the context of 22 the company's 2002 rate case application. 23 The company is also proposing that the actual 24 inventory credit stemming from the revaluation of the 25 inventory balance as of December 31, 2000 be applied as 26 an offset to the 2001 PGVA year-end balance. 27 So as a result of that proposal, given that 28 the current projections for the year-end balance in the 11 1 PGVA is $88.1 million, and given that the projection for 2 the inventory revaluation product is $73.7 million, when 3 we take the $88.1 minus the $73.7 million, the net 4 results amount to a net charge of $414.4 million, that 5 would reside in the PGVA. 6 So all other things being equal, were the 7 company to clear $14.4 million at the end of the 2001 8 fiscal year, that would amount to a one-time charge of 9 approximately $8.00 for a typical residential customer. 10 Finally, I would like to conclude by saying 11 that all the detailed evidence supporting the cost 12 allocation and rate design are found under P3, Tabs 4 13 and 5. 14 So that concludes my summary. 15 MR. FARRELL: I thought maybe we would have 16 each of the witnesses give their summaries, unless 17 people want to ask questions sequentially. 18 What is your preference? 19 MR. SCHUCH: I prefer to have them go all 20 through. 21 Don. 22 MR. SMALL: Okay. 23 What I would like to do is, if I could draw 24 your attention to the exhibits that I am primarily 25 responsible for, and they are found at P3, Tab 1, 26 Schedules 1 and 2. 27 First off, I would like you to take a look at 28 Exhibit P3, Tab 2, Schedule 1, page 2 of 2. That 12 1 exhibit represents or is just a recreation of the 2 company's forecasted purchase volume and the associated 3 costs that we filed as part of the new rate case. In 4 fact, you will see at line item No. 8 the $245 per 5 10(3)m(3), which was the approval PGA reference price 6 effective October 1. So that ties in almost exact -- 7 well, it ties in exactly with the exhibit that we filed 8 as part of the main rate case at D3, Tab 2, Schedule 1. 9 Now, Exhibit P3, Tab 1, Schedule 1, page 1 10 of 2, is simply taking those same forecast levels of 11 purchases and applying to them a new 21-day average of 12 prices to come up with what we are seeking here as the 13 new PGA reference price to be effective January 1. You 14 will see at line item 8 a PGA reference price of 15 $282.617 per 10(3)m(3). 16 So you see that the volumes -- again, the 17 total purchase volumes in line 8 correspond with the 18 volumes on page 2 of 2 of that same Schedule. So we are 19 just taking the forecast level of purchases and 20 receipts, and again using a new 21-day average to come 21 up with that new PGA reference price. 22 If you turn to Exhibit P3, Tab 1, Schedule 2, 23 page 1, what this exhibit is intended to show is that if 24 you -- it's just a monthly breakdown of those forecasted 25 purchase volumes. You will see at the bottom of the 26 page there is a subtotal and it would be -- you will see 27 again the same volume of 5680513.6 10(3)m(3). All we 28 are attempting to show here is that month over month 13 1 there is going to be fluctuation in price versus the 2 282 PGA reference price, but at the end of the 12-month 3 period, in this case December 31, 2001, you would have a 4 zero balance in that PGA account, if you had one over 5 that 12-month period. 6 Exhibit P3, Tab 1, Schedule 2, page 2 of 2 is 7 providing a projected balance in the 2001 PGVA account, 8 so the balance at the end of September 30, 2001 is the 9 balance that Ms Duguay was referring to, the 88 million. 10 It is a combination of telemetered and estimated volumes 11 that we think we are going to be purchasing throughout 12 the fiscal year. It is slightly different than what our 13 budget was, but that is not uncommon. We are updating 14 for things as we are going through the year. 15 We would be applying the current prices to 16 those volumes and referencing them against the 245 PGA 17 reference price for the months October, November and 18 December, and then referencing it against the updated 19 PGVA reference price of 282 from January onward, and 20 that gives you a PGA balance of 88 million, which we 21 then, as Ms Duguay said, would plan to offset by the 22 inventory revaluation of December 31. 23 MR. BRENNAN: I will try to give you a bit of 24 an update on gas prices. I believe about three months 25 ago I did the same thing. Not much has really changed 26 in terms of what is driving the gas prices. Basically 27 it is the increase in demand for natural gas. Natural 28 gas still remains the fuel of choice. There is a high 14 1 demand for natural gas on the electric side to generate 2 power and there is, I guess, the supply situation. That 3 has not changed over the last three months. 4 I think, though, what we are seeing, at least 5 in November of this year, is at the beginning of the 6 month that we had some milder weather, there was and 7 expectation or a hope, I guess, that injections into 8 storage would increase and get those balances up to 9 where the norm should be. An attempt was to do that, 10 but half way through the month we experienced some cold 11 weather throughout the country and back into withdrawal 12 mode. 13 So those storage balances are not as high as 14 they had been in past years and I think what we are 15 seeing now, the run up in prices or the volatility in 16 prices is more related to what is happening with the 17 weather. 18 If the weather over the rest of the winter 19 continues to be colder than normal, then I think we will 20 see prices increase over that period. If weather is 21 milder than we expect, then those prices could drop. I 22 think the emphasis is that they are very volatile at 23 this point and I think that is what we have put here in 24 terms of arrestment of what gas prices are going to be 25 over the next 12 months. It is probably the best we 26 could do at this time. 27 MR. BOURKE: My exhibits are found in 28 Exhibit P3 at Tab 2. My exhibits are designed to 15 1 calculate the annualized impact of the increase in the 2 PGVA unit rate and the amount that we need to recover. 3 At Schedule 1 in that Tab 2, I have taken the 4 forecast utility gas cost volume, excluding T service, 5 at line 5. This amount is slightly different than the 6 amount Mr. Small spoke of, five million six eighty, in 7 his exhibits for the amount of purchases. 8 The amount is found in the exhibit that he has 9 filed in the main rates proceeding, the difference is 10 the fluctuation of storage volumes that reduces the 11 5,680,513.6 10(3)s of purchase and receipt volume that 12 he has and has spoken of this morning reduced by a 13 storage fluctuation of 189,309.3 to give me the volume 14 to which I have applied the PGVA unit rate difference, 15 that volume being 5,491,204.3. Extended by the increase 16 in the proposed change in the PGVA unit price gives me a 17 total upstream impact of two hundred and four million 18 three hundred point two. 19 To that amount, I might point out that on my 20 Schedule 1 at line 7 and 8, you can see that there has 21 been no attempt to forecast any change in TCPL toll 22 costs in this application. 23 The amount of 204 as the gas pass-on cost, we 24 have added the increased carrying cost requirement as a 25 result of the changes in the PGVA unit price on rate 26 base values in the amount of 7.1 million at line 10 on 27 that schedule. 28 The supporting schedule for those calculations 16 1 is the next page, my Schedule 2, in which we have 2 calculated the change of the value of gas in storage 3 shown at line 2 in the amount of 60.6 million on an 4 annualized basis. To that amount we have added the 5 effect on working cash allowance in the amount of 6 2.2 million shown at line 3.4 and the effect on goods 7 and service tax, carrying costs, in the amount of 8 600,000 for a total change in rate base of 63.3 million. 9 When multiplied by the gross return component, the 10 increased carrying cost is 7.1 million. 11 Returning to my Schedule 1, that value of 12 7.1 million is added to the upstream gas cost impact of 13 204.3 to give a change in the revenue requirement of 14 211.4 million, which is the amount which Ms Duguay 15 explained the difference of 4.6 million in generating 16 the amount which is to be or the company proposes to 17 recover in rates of 206.8. 18 MR. FARRELL: I think we are at the question 19 stage now. 20 MR. SCHUCH: Mr. Warren, do you have any 21 questions? 22 MR. WARREN: Just a couple of mechanical 23 questions, first of all, in terms of numbers. If the 24 rates weren't increased, what would the PGVA balance be 25 as of January 1? 26 MR. SMALL: Pardon me? Sorry. 27 MR. WARREN: If the rates were not increased 28 now, what would the PGVA balance be approximately? 17 1 MR. SMALL: You could calculate that if you 2 went to Exhibit P3, Tab 1, Schedule 2, which we have 3 generated a forecast of 88 million at the end of 4 September. And if you maintain the PGVA reference price 5 of 245,412 dollars per 10(3)m(3), you would get a PGVA 6 balance of approximately $250 million. 7 MR. WARREN: And are you able to do a rough 8 calculation of what the one-time charge for residential 9 customers would be if you cleared that? 10 MS DUGUAY: I could calculate it but just as a 11 reference in the letter that was sent to the OEB signed 12 by Mr. Grant, the projected PGVA balance at that time 13 was 270 million, which is fairly -- in the ballpark of 14 the number that Mr. Small just quoted. And that would 15 resolve or amount to a one-time charge of about $155 for 16 a residential customer. It would be a little bit lower 17 than that. 18 MR. WARREN: Okay. Now, do I take it that 19 your reason for not proposing to clear the PGVA in 20 January 1 is that with the effect of the inventory 21 revaluation it will ultimately be a lower number, is 22 that right, down the road in terms of its impact on the 23 typical residential customer? 24 MR. SMALL: Well, I guess it is a combination 25 of things. If we were to clear the PGVA balance at 26 December 31st, we would have -- if you look at, based 27 upon this forecast of information, we would have to 28 clear a balance of $103 million, which would be 18 1 something in the neighbourhood of -- I'm not exactly 2 sure how much it would be per typical customer, but it 3 would be a lot more than the $35. 4 MS DUGUAY: I have this information. Were we 5 to clear the balance at the end of December, that would 6 amount to a one-time charge of approximately $60 per 7 residential customer. 8 So basically the rationale supporting the fact 9 that the company is not proposing to clear the PGVA at 10 that stage is first thing the company wanted to keep 11 this or deal with this proceeding on an expeditious 12 basis. The company didn't want to further aggregate 13 this financial burden to residential customers and other 14 customers as well by changing its rates effective 15 January 1 and further clear the PGVA balance which would 16 amount to a one-time charge of approximately $60. 17 And also I think that clearing the PGVA 18 throughout the course of the year would amount to 19 clearing the temporary variance. As you know, the PGVA 20 is set on an annualized basis so typically the company 21 likes to clear the PGVA balance on an annualized basis 22 as well, that is covering a full 12-month period. 23 MR. SMALL: Just to go one step further, if 24 you were to clear that balance of 103 million that is 25 shown on this schedule here, then by the time you got to 26 the end of September you would have a $15 million, 27 approximately a $15 million balance that would have to 28 be returned to customers, plus we would also have the 19 1 balance that is in the PGVA as a result of revaluing the 2 inventory, which is approximately 73 million. So we 3 would be on the one hand collecting from customers to 4 clear $103 million and then we, at the end of September 5 if everything fell according to our projections, we 6 would be giving back to the customers some $88 million. 7 MR. WARREN: Mr. Small, could you just 8 identify by exhibit number the page you are referring 9 to. You have been referring to this exhibit, so just 10 for the record. 11 MR. SMALL: Sorry. I was referring to 12 Exhibit P3, Tab 1, Schedule 2, page 2 of 2. 13 MR. WARREN: You mentioned TCPL toll 14 increases. I take it that they are forecasts to 15 increase? 16 MR. BRENNAN: Yes, they are. 17 MR. WARREN: When is that likely to take 18 place? 19 MR. BRENNAN: Well, negotiations are going on 20 now with shippers and TransCanada with the idea of 21 hoping to have a settlement prior to January 1. I think 22 though that where we are with the negotiations now that 23 TransCanada will in all likelihood be seeking interim 24 tolls effective January 1. 25 Our expectation is that they will be filing an 26 application sometime in December for interim tolls for 27 January 1, and final tolls sometime in 2001, whenever 28 either the negotiations conclude or they have to go to a 20 1 hearing. 2 MR. WARREN: What is the rationale for not 3 reflecting some forecast of the anticipated toll 4 increase in this charge now? 5 MR. BRENNAN: I guess the short answer is we 6 simply don't know what TransCanada's tolls are going to 7 go to. 8 MR. WARREN: Not even a reasonable estimate of 9 what it is? 10 MR. BRENNAN: We would be speculating. We 11 have had numbers from TransCanada, depending on what 12 they want to include in interim tolls. 13 MR. WARREN: What happens when they do 14 increase? Will they be back to the Board? Can I 15 presume you would be back to the Board asking for 16 another increase to reflect TCPL charges? 17 MR. BRENNAN: It would depend on what that 18 increase is and what it does to our trigger mechanisms. 19 MR. WARREN: A final couple of areas of 20 questions. I may have to rely on Jerry for answers to 21 this. 22 I have not been directly involved in one of 23 these gas cost increases for some time so my 24 recollection is both ancient and probably incorrect. 25 Do I take it that the gas costs we are looking 26 at now are a reflection of the play of market forces of 27 the kind you have described plus your efforts to 28 mitigate them through contractual arrangements, risk 21 1 management and that kind of thing? Is that fair? 2 MR. BRENNAN: Yes, I think that's fair. 3 MR. WARREN: Okay. Jerry, I will look to you. 4 If you could help me on this. 5 When is it, if it all, that we review those 6 risk management activities? Is it in a main rate case 7 or is it -- I didn't think it was typically in the 8 context of these kinds of proceedings, but isn't it a 9 main rate case? 10 MR. FARRELL: Yes. 11 MR. WARREN: Would you expect, in the ordinary 12 course, that in the 0040 proceeding we would be 13 reviewing those risk management activities and the 14 contracting arrangements that have been made? 15 MR. FARRELL: If that is on the Issues List. 16 MR. WARREN: If it isn't and I asked it to be, 17 what would be the company's position? 18 MR. FARRELL: Why don't we talk about that in 19 the Settlement Conference. 20 MR. WARREN: Okay. That's fine. That's fair. 21 I just have one last -- sort of technical 22 questions. 23 Assuming that this rate increase is approved, 24 do you plan a customer education communications strategy 25 to communicate to customers why this is happening and 26 explain the magnitude? 27 MR. BRENNAN: Yes, we do. We have been doing 28 that for several months now. We have had meetings with 22 1 several groups, including the Ministry of -- maybe I 2 won't start there. 3 With customers, they have been bill inserts. 4 The pipeline newsletter has gone out to all our 5 customers to explain what the increase is all about, 6 what is causing the increase. We have also included in 7 those newsletters energy efficiency tips. We have also 8 included a $15 rebate for a programmable thermostat. 9 So, yes, I think we have been communicating 10 with the customers. In fact, just last week there was a 11 group of Enbridge employees that made a presentation to 12 the Ontario Senior's Secretariat explaining how natural 13 gas pricing works and what is causing these price 14 increases. 15 MR. WARREN: Okay. Thanks. Those are my 16 questions. 17 MR. SCHUCH: Mr. Adams. 18 MR. ADAMS: I wanted to try two different 19 lines of questions with you. 20 The first one relates to the relative risk of 21 these different balances. It occurs to me, and I wonder 22 if the company would agree, that the degree of risk 23 associated with forecasting the inventory re-evaluation 24 levels and TCPL tolls is substantially greater because 25 of the time duration than the risk associated with 26 anticipating PGVA balances over the next three months. 27 Is that reasonable? 28 In your own minds, when you are trying to 23 1 evaluate these different financial impacts, do you weigh 2 them with any different risk? 3 MR. SMALL: I'm not sure I entirely understand 4 your question. 5 As part of our risk management program we are 6 always updating for a new 21-day average each and every 7 day to see what our projected costs will be, purchase 8 costs will be. We will be examining the volatility 9 around those commodity prices to see what impact they 10 would have. 11 With TCPL, we certainly have an idea as to the 12 magnitude of that increase in the tolls, but we wouldn't 13 want to bring forward a forecast at this time because, 14 as I understand it, there could be a big difference 15 between what those final tolls would be and what 16 TransCanada may be asking. At the same time, we 17 wouldn't want to necessarily put something into the 18 forecast because it may hinder us through our 19 negotiations with TCPL. 20 MR. ADAMS: Here is the proposition. We have 21 a PGVA balance right now that is substantial. You are 22 hoping that you are going to get some offsets against 23 it. We have positive knowledge about the actual deficit 24 in the PGVA account right now, and we have speculation 25 about what the offsets are going to be. The 26 presentation you made presents those two figures, the 27 debits and the credits, as if they have equal value. 28 I'm just wondering whether you accept that as 24 1 realistic. One seems to be very forecast-based and one 2 is a real problem we have right now. 3 MR. SMALL: I guess part of my problem is I 4 don't quite understand where you are coming from. Maybe 5 if I just back up a bit and try to give you an 6 explanation as to how we come up with the forecast of 7 what the projected year end PGVA balance would be. 8 We are always taking a 21-day average of 9 prices reported in the marketplace for each month going 10 forward. We would apply that average to a forecast of 11 what we are expecting our purchases to be. So while we 12 may estimate what our update for what that purchase 13 volume will be, the price forecast is a forecast that we 14 are generating. We are just picking up the market 15 information and saying, okay, this is now what we think 16 it is going to cost us to buy our gas supplies up to 17 this point and for the remainder of the year. When you 18 compare that to the PGVA reference price, you are coming 19 up with a balance, a projected balance, in the account. 20 MR. ADAMS: Let me try something else here. 21 I haven't reviewed your filing properly, and I 22 apologize if you have spoken to this matter. Has the 23 company made any consideration for revising its GCAM 24 proposal? 25 MS DUGUAY: Not recently, no. 26 MR. ADAMS: Not revising. Bringing it back to 27 life. 28 MS DUGUAY: That certainly will be something 25 1 we will be looking into in the future. Certainly, I 2 think, in light of the volatility that we are facing in 3 the marketplace now, I think there is a need to review 4 the current methodology. 5 MR. SMALL: If I could just add. 6 If we take a step back for a second, I mean, 7 we were here and we had an upstream June 1 of 2000. We 8 came forward and we were able to implement new commodity 9 prices for October 1. Now we are coming forward for an 10 upstream January 1. I mean, I don't know how much more 11 quarterly you can get than that. 12 MR. FARRELL: Something that, Tom, you may not 13 be aware of, in the settlement proposal for the October 14 1st increase we accepted, as an issue to be examined in 15 the main case, the trigger methodology applicable to the 16 PGVA and the related rate adjustment mechanisms. So 17 that is an issue that will be ventilated in the main 18 case. 19 MR. ADAMS: Okay. Thank you, Jerry. I 20 appreciate that. 21 It occurs to me that from my recollection of 22 your historic submissions on -- or evidence on DCAM -- 23 it was never brought forward, actually, in the hearing, 24 that the approach that you adopted with that proposal 25 was somewhat inconsistent with the approach that you are 26 proposing here. 27 MR. SMALL: First off, I would like to 28 apologize. When you are talking about the DCAM, I 26 1 thought you were talking about a quarterly mechanism 2 similar to what Union Gas is. A number of intervenors 3 has suggested we should go to something like that. I 4 apologize. 5 MR. ADAMS: I think the DCAM was somewhat 6 further along. 7 MR. SMALL: I am trying to -- 8 MR. ADAMS: It was a monthly adjustment 9 mechanism with the PGVA balance thrown into the next 10 figure. It was a rolling process. 11 MR. SMALL: And I am trying to -- I mean, it 12 was about three or four years ago, I believe, and I 13 can't quite remember all the -- 14 MS DUGUAY: I am in the same situation. 15 I recall that -- as I recall it, we filed a 16 DCAM proposal back in E.B.R.O. 492. I stand corrected 17 if my memory fails. 18 MR. FARRELL: I think it is 495. 19 MS DUGUAY: Subject to check, I will accept 20 that. 21 --- Laughter 22 MS DUGUAY: I -- 23 MR. FARRELL: At any rate, I don't know 24 whether we are going to get too much farther debating 25 this at this point because the witnesses don't recollect 26 and it is an issue for the main case. 27 MR. ADAMS: Okay, thank you. No more 28 questions. 27 1 MS YOUNG: I just have a few questions. 2 The first one relates to the $5.96 per 3 gigajoule, the western Canadian price at Empress 4 forecast. Mr. Small, this may be for you. 5 MR. SHCHUCK: Do you have a reference? 6 MS YOUNG: Yes. Oh, sorry. 7 Yes. It is Exhibit P2, Tab 1, Schedule 1. 8 The 5.96, is it strictly the 21-day average of 9 the 12-month CGPR strip for the calendar 2001? 10 MR. SMALL: That is right. If I take the 11 21-day average of prices for the month of January 2001 12 to December 2001 of Empress prices, and then the 13 12-month average of those prices, I get 5.96. 14 MS YOUNG: Okay. So it doesn't have a built 15 in as part of the averaging process, any of the impact 16 of risk management activities? 17 MR. SMALL: No, it doesn't. What we would do 18 is we would take the 21-day average of not just the 19 Empress but to the extent that some of our contracts may 20 be -- there are a very few of them that are NYMEX-based. 21 We would apply those prices to the various contracts 22 that we would have in place or make some assumptions 23 with respect to discretion and supplies. 24 So the 5.96 is to provide an illustration, if 25 you will, of what those prices would be if you were 26 buying strictly in Empress. 27 MS YOUNG: So essentially a market benchmark 28 for the reporting period? 28 1 MR. SMALL: Yes. 2 MS YOUNG: And the reporting period was 3 October 10 to November 7. 4 MR. SMALL: That is right. 5 MS YOUNG: What would the average be if you 6 used a more recent 21-day average? 7 MR. SMALL: It would be higher. 8 --- Laughter 9 MS YOUNG: Do you know by how much, any sense? 10 MR. SMALL: Pardon me, sorry? 11 MS YOUNG: Any sense of how much higher? 12 MR. SMALL: It would be -- I did take a look 13 at what the 21-day average of Empress prices would be 14 for the October 24 to November 21 period and those 15 prices would average out to over $6.00, approximately 16 $6.15. 17 --- Pause 18 MS YOUNG: And if the impact of the 6.50 -- 19 MR. SMALL: Sorry, 6.15? 20 MS YOUNG: It's 6.15, sorry. 21 And if that 21-day average were used in 22 determining the gas cost increase, that would have -- 23 the gas supply charge would obviously go up by whatever 24 the amount would be. But that would also have the 25 impact of -- well, what would be the impact on the PGVA 26 as you worked your way through the rest of the fiscal 27 year? 28 MR. SMALL: I haven't gone that extra step. 29 1 The only thing I would like to mention though is that to 2 the extent that we have entered into risk management 3 activity, then the dollar impact of those risk 4 management will be taken into consideration so it is 5 possible that with the increase in prices there be 6 additional benefits through the risk management. 7 So I just caution you to not just assume that 8 the full increase would be impacted upon the PGVA 9 account. 10 MS YOUNG: Okay. 11 MR. SMALL: But I haven't figured out what 12 that number would be. 13 MS YOUNG: Thanks. And has there been any 14 thought given to updating the evidence for a more recent 15 21-day average? 16 MR. BRENNAN: I don't think so at this time. 17 I think, you know, as I mentioned earlier, prices are 18 very volatile and while it may look like right now that 19 they could be going up, by the time we got there they 20 could be dropping again. So I think what we are saying 21 is what we have here is probably our best estimate right 22 now. 23 MS YOUNG: Moving forward then, recognize that 24 the prices in the market are extremely volatile and 25 expected to continue to be that way, I think also 26 perhaps some of the market fundamentals as they are at 27 work right now would suggest that there will continue to 28 be an upward pressure on prices, certainly as we move 30 1 through the winter and possibly next summer. 2 If that turns out to be the case or given 3 that, would it be the company's intention then to 4 continue to monitor the situation as you have done in 5 the past couple of increases, continue to monitor the 6 situation then if the $35.00 trigger is reached back in 7 with a gas cost increase application until the main 8 hearing and the issue is discussed -- the methodology is 9 discussed? 10 MR. BRENNAN: Yes, that is correct. 11 MS YOUNG: Thanks. Those are all my 12 questions. 13 MR. SCHUCK: Mr. Haynal. 14 MR. HAYNAL: Thank you very much. 15 MR. SCHUCK: Mr. Robertson, no questions? 16 MR. ROBERTSON: No questions. 17 MR. SHCUCK: I have a couple of questions. 18 In reference to P2, Tab 4, Schedule 1, 19 paragraph 7, in this paragraph the evidence talks about 20 the forecasted inventory revaluation credit of 73.7 21 million and the fact that the PGVA would be lowered by 22 the amount of its credit and that the net PGVA at the 23 end of the fiscal year would be 14.4 million after the 24 credit. 25 I wonder if you could just tell me when will 26 you know the actual amount of the revaluation credit? 27 MR. SMALL: We would have telemetered 28 information available to us within the first couple of 31 1 days of January. But before we could get our final 2 invoice information, you are probably looking -- before 3 we could up with a final balance, you are probably 4 looking at some time around January 20th. 5 MR. SCHUCH: What reference price would be 6 used for the calculation of the 73.7 million? 7 MR. SMALL: You take the difference between 8 our proposed PGVA reference price of $282 and the 9 current one of $245 -- 10 MR. SCHUCH: Right. 11 MR. SMALL: -- which is a $37.205 per 12 10(3)m(3) change, and I believe if you turn to 13 Exhibit P3, Tab 2, Schedule 4, you will see how the 14 $73.6 million is calculated. 15 MR. SCHUCH: All right. Thank you. 16 So I am wondering if the actual inventory 17 credit when it is known would it be then applied to the 18 PGVA balance at that time? 19 MS DUGUAY: Yes. 20 MR. SMALL: Yes. 21 MS DUGUAY: So we would do the calculation as 22 seen at P3, Tab 2, Schedule 4 and provided that the 23 Board would approve the reference price in this 24 application, the 282.617, the differential applying to 25 would be the same. We would update line 1 to reflect 26 actual volumes of gas and inventory and the inventory 27 credit, which is the product of those two lines, would 28 then be applied as an offset to the PGVA. 32 1 MR. SCHUCH: Thank you. 2 Is it the company's intention that the 3 14.4 million, which I recognize is the forecast at this 4 time, that amount would be clear to customers by a 5 one-time charge? 6 MS DUGUAY: Well, in light of what it 7 represents for a typical residential customer, I 8 mentioned earlier in this summary that that would 9 translate to a charge of about eight dollars for a 10 typical residential customer. That would certainly fall 11 within the boundaries of the trigger mechanism. I would 12 presume, yes, that this would be dealt with through a 13 one-time charge. 14 MR. SCHUCH: And when would that charge likely 15 be collected? Would it be in the October 2001 billing 16 cycle or later likely? 17 MS DUGUAY: It depends where we are in terms 18 of the timing of the fiscal 2002 proposal. Because 19 typically the declaring of the deferral account, the 20 Board will approve it within its decision in the main 21 rates case and depending when we file, when we have a 22 decision from the Board. We have been in the past 23 fairly much on track to clear it in the first -- 24 starting in the first billing cycle of October. This 25 year, as you know, we have cleared the 2000 PGVA in 26 November. So I would suspect that it would be around 27 that time. 28 MR. SCHUCH: Thank you. 33 1 I have another question regarding Exhibit P3, 2 Tab 1, Schedule 1, page 1 and that is the gas cost to 3 operations. And this is the table for the year ended 4 December 31, 2001. I just wondered if you could confirm 5 that this is the schedule that derives the reference 6 price of 282 per 10(3)m(3)? In other words, you would 7 input all of the component pieces in this schedule and 8 the final number, the 282, pops out. Is that how that 9 number is derived? 10 MR. SMALL: Essentially. We would take the 11 21-day average and come up with a price for each 12 individual month, apply those prices to our forecasted 13 level of volumes and whatever the annual cost is, you 14 are going to come up with the unit rate and that unit 15 rate is the 282. 16 MR. SCHUCH: So it is derived -- it is 17 initiated from another schedule, monthly schedule, is 18 that what you are saying, and then it is transposed on 19 to this one? 20 MR. SMALL: Well, as part of my gas cost 21 model, I input all the various pricing information, all 22 the volume information and it will calculate the 23 individual monthly purchases. And then it will say, 24 okay, here is what the annual expected purchase costs 25 are going to be. Whatever that unit rate is becomes the 26 PGVA reference price. So on a month-to-month basis you 27 then bring or adjust those monthly purchases back to the 28 PGVA. So you end up with a zero balance at the end of 34 1 the year because you still come back to that annual 2 purchase cost. 3 MR. SCHUCH: Is the model that you refer to 4 included in the evidence here? But is perhaps one of 5 these -- 6 MR. SMALL: I mean you can -- essentially when 7 you look at P3, Tab 1, Schedule 2, page 1, you will see 8 the monthly purchase costs and the monthly volumes that 9 when they are compared against the PGVA reference price 10 of 282 you will get a forecasted PGVA adjustment on a 11 monthly basis. It comes to zero. But if you go down to 12 the bottom of that page, the subtotal, the annual 13 purchase cost, when you take into consideration the 14 volumes you get a unit rate of 282. 15 --- Pause 16 MR. SMALL: I guess maybe -- they are one in 17 the same thing really. I mean Exhibit P3, Tab 1, 18 Schedule 1 is an annualized summary of all those costs 19 and you can still see that you come back to that average 20 price of 282. The exhibit at P3, Tab 1, Schedule 2 21 identifies the month-to-month dollar amounts and 22 volumes. So they are showing the same thing really 23 but -- 24 --- Pause 25 MR. SCHUCH: Okay. Thank you. 26 I have got another question with reference to 27 P3, Tab 1, Schedule 2, there is two tables. One is 28 12 months ended December 31st 2001, and another one is 35 1 12 months ended December 30th 2001. 2 Now, I think, Mr. Small, I think you have 3 touched on some of this in your opening comments but I 4 just wanted to clarify a couple of things. 5 Looking at the column for the monthly forecast 6 of volumes on these tables, the forecast is different 7 for each table. In fact, eight months are different and 8 four are the same. 9 MR. SMALL: Well, if I could try to explain it 10 this way. 11 When we are preparing an upstream, our 12 starting point is that we want to take the 13 Board-approved volumes. I mean it is a little difficult 14 because technically the purchase volumes haven't been 15 approved by the Board. I mean we have got acceptance of 16 them for purposes -- from the Settlement Conference. 17 But we would take those 12 months and 18 dependent upon when we want to implement the PGVA 19 reference prices, we would essentially say okay, we have 20 got 12 months worth of purchases. If we are now going 21 to have an upstream January 1, we still would have the 22 same 12 months worth of purchases. 23 In this case, the forecast volumes for October 24 2000 are now forecast for October 2001. So you still 25 have the same 12-month total volumes but you are 26 applying a new 21-day average to those prices. 27 That is why on Exhibit P3, Tab 1, Schedule 2, 28 you will see it is the 12-months January to December and 36 1 it is still the same volume. We are saying that if you 2 take that 12-months worth of purchases and shift it into 3 a different 12-month time frame, you still have the same 4 volumes that we are trying to come up with a new unit 5 rate that we can impose upon or increase our commodity 6 cost by effective January 1. 7 MR. SCHUCH: Do you mean the same volumes and 8 totals? 9 MR. SMALL: Yes. 10 MR. SCHUCH: But they are not the same. 11 MR. SMALL: If you look at P3, Tab 1, 12 Schedule 2, page 1, they are the same as the volumes 13 reported on P3, Tab 1, Schedule 1. 14 MR. SCHUCH: Right. Right. Which tie into 15 the originally filed volumes back in August. 16 MR. SMALL: In D3, yes. That's right. 17 That Exhibit P3, Tab 1, Schedule 2 is intended 18 to show here the month-to-month purchase costs that come 19 back to it, two-eighty-two, so that you can see that for 20 the January to December period you would come back to a 21 zero balance if you were looking at a PGVA over that 22 12-month period. 23 What we attempted to do as part of P3, Tab 1, 24 Schedule 2, is no different than what we have shown in 25 other upstream applications. We have said, okay, fine, 26 we know that our purchase volumes are going to be 27 something different than what our budget in fact is. It 28 is a little unique in this case because we are so early 37 1 in the year, but if you looked at -- 2 MR. SCHUCH: Could I just stop you there. 3 So it is an updated budget. Is that what you 4 are saying? 5 MR. SMALL: It's not an updated budget. 6 What we try to do, when we are looking at what 7 our projected balance is in the PGVA account, in this 8 case the projected balance in 2001, we are going to be 9 updating on a daily basis for a new 21-day average of 10 prices, but at the same time we are going to be 11 evaluating what our supply portfolio is. It is quite 12 possible that you are going to have changes in your 13 supply portfolio is. It is quite possible that you are 14 going to have changes in your supply portfolio, 15 differences from what you thought your budgeted forecast 16 was going to be. 17 You have now started going to the fiscal year. 18 Your demand might be slightly different than your 19 budget, so you are going to be adjusting your portfolio 20 to satisfy that demand. One of the things that we are 21 going to be trying to do is trying to maintain our 22 targeted storage balances. 23 So there could be a shift of the total volume 24 that you are going to be buying. We may shift when we 25 think we are going to be buying supplies. To the extent 26 that they are on a delivered basis, we may say, well, 27 instead of buying some gas in the month of May, for 28 example, we may delay that purchase until June, 38 1 dependent upon what the demand is that we are expecting. 2 We are always updating that. 3 We may have also locked in some of our 4 contracted supplies that we initially identified as 5 being discretionary. So we are constantly updating it 6 so that we can come up with what we think is a most 7 up-to-date projection of our PGVA balance. 8 MR. SCHUCH: Would you describe it as a living 9 document, sort of thing? 10 MR. SMALL: That's fair. 11 MR. SCHUCH: When you were talking about the 12 updating, Mr. Small, you were talking about page 2 of 2? 13 MR. SMALL: Yes, I am, which generates the 14 projection of $88 million at the end of the year -- 15 PGVA. 16 MR. SCHUCH: On that page 2 of 2, would 17 October represent an actual? 18 MR. SMALL: At the time that we prepared this 19 it wasn't an actual, it was in fact a telemetered. 20 There is a little bit of a difference. Telemetered is 21 based upon what we have dominated. We haven't received 22 our invoices at the point of time that we would have 23 prepared this. 24 MR. SCHUCH: Okay. 25 In a related question, and the answer may be 26 very similar to what I just heard, I noticed that the 27 prices beside the volume forecast for each month show 28 different prices for these two schedules for every 39 1 month. 2 MR. SMALL: That would be because of the 3 difference in the forecast. 4 MR. SCHUCH: The difference in the volumes. 5 MR. SMALL: Yes. It is going to -- 6 MR. SCHUCH: So that it produces a different 7 price. That's fair. Okay. Thank you. 8 Would it be fair to say that if there was a 9 change in any of these variables on these tables that it 10 would result in a change to the reference price? 11 MR. SMALL: If you are talking about page 2 of 12 2, any change in the volumes or the pricing assumptions 13 would change the expected or projected balance in the 14 PGVA. It wouldn't change the reference price because 15 what we would still be saying is that we want to come 16 back to a projected PGVA reference price of the 282. 17 That becomes frozen. 18 MR. SCHUCH: Thank you. That's helpful. 19 Another subject that was touched on in your 20 presentation, and I think some questioning too from 21 Mr. Warren, was on this subject of risk management and 22 hedging. I wondered if one of you would be able to give 23 us a really brief overview as to the company's hedging 24 policy as it relates to gas supply. 25 MR. BRENNAN: In 25 words or less? 26 I guess the objective of the gas supply risk 27 management program is to not necessarily generate the 28 lowest cost or price. What it is trying to do is 40 1 minimize the volatility in pricing. 2 The parties I think want to have 3 market-responsive prices and, as a result of that, you 4 are going to get volatility in those prices. So what we 5 are trying to do is minimize the volatility. 6 We obviously do not speculate on where prices 7 are going. We have a model that looks at where we think 8 prices are going in the future based on the current 9 strips. We have a certain amount that we are able to 10 hedge at any one particular time. There is an approval 11 process that goes through that, to make sure that all 12 those policies are kept in place. 13 MR. SCHUCH: An internal approval process or a 14 board approval process? 15 MR. BRENNAN: It is our own internal. 16 So what this model generates, I guess, is what 17 our best option is in terms of whether we should be 18 putting in a cap, a collar or a swap. 19 MR. SCHUCH: You will be able to estimate what 20 percentage of your total current supply portfolio is 21 currently hedged? 22 MR. BRENNAN: I am going from memory here. I 23 believe of the volume that is hedgable, I think it is in 24 the neighbourhood of around 30 per cent. 25 MR. SCHUCH: Thirty? 26 MR. BRENNAN: Thirty, 30. 27 MR. SCHUCH: Thank you. 28 MR. LADANYI: Colin, I might like to add, you 41 1 might not be aware because you haven't been involved 2 recently in these cases, but the risk management policy 3 was before the Board, was examined by the Board and was 4 approved by the Board. We are strictly following the 5 Board-approved policies here. 6 MR. SCHUCH: Thank you. 7 I have one more question, and that is in 8 reference to Exhibit P3, Tab 1, Schedule 1, page 1. 9 Specifically, I am looking at line 6.10 and 6.11. That 10 is the Alliance and Vector transportation costs which 11 are shown at $40 million and $23 million roughly. 12 I noticed that these cost items have not 13 changed since the August filing. In the interim, I 14 believe there has been at least two delays in the 15 start-up of the Alliance-Vector system which I believe 16 was scheduled for sometime around October 1st. Is that 17 correct? 18 MR. SMALL: It was originally expected to be 19 in service October 1, yes. 20 MR. SCHUCH: When is it currently expected to 21 be in service? 22 MR. BRENNAN: Both Alliance and Vector, from 23 my understanding, is December 1st. 24 MR. SCHUCH: I'm wondering, would this delay 25 not have an impact on these transportation costs? 26 MR. SMALL: You have to remember that our 27 budget was based upon satisfying a certain demand and to 28 satisfy that demand, we would also maintain certain 42 1 targeted storage balances on a monthly basis. To the 2 extent that had we known when we were preparing the 3 original budget that the Alliance and Vector Pipelines 4 would not be in service until December 1, to satisfy or 5 to meet our forecasted demand and our budget storage 6 targets, we would have had to acquire the same amount of 7 gas in the month of October and the month of November so 8 if Alliance and Vector weren't available, we would have 9 had to go out and acquire that gas on a delivered basis. 10 So what you would have seen is a reduction in the 11 transportation cost at items 6.10 and 6.11. 12 You would have also seen a reduction in 13 item 4.3, western discretionary supplies, because that 14 is where the quantity is forecasted or is grouped that 15 we would be moving through the Alliance pipeline or 16 forecasting to move through the Alliance pipeline. 17 So you would have seen reductions there but 18 you would have seen an increase in 4.4, Ontario 19 delivered, because we would have had to still go out and 20 buy the gas supply and you can tell by the unit rate on 21 that line item that it is a delivered supply so it is a 22 delivered unit rate. So we would have -- while we may 23 have lowered our transportation costs, our 24 Ontario-delivered supply costs would have increased 25 because we still would have had to buy the gas and it 26 would have had a minimal effect on the two-forty-five 27 PGA reference price. 28 MR. SCHUCK: I think essentially what you are 43 1 saying is that one would offset the other and it doesn't 2 really matter. 3 MR. SMALL: That is right, minimal, that is 4 right. 5 --- Pause 6 MR. SCHUCK: Thank you. Those are all our 7 questions. We are right on for 10:30. Should we break 8 now and reconvene for the settlement portion? 9 Does anybody else have any more questions? 10 --- Pause 11 MR. FARRELL: We can do that. We have copies 12 of a draft settlement proposal that do not reflect the 13 parties that are here necessarily, just used the ones 14 that were from the last one. But maybe we could go off 15 the record now and I could explain what is in here and 16 then people could use the break to look through it and 17 we would use that maybe as a starting point for 18 discussions in the Settlement Conference. 19 --- Off record discussion 20 --- Whereupon the technical conference concluded at 1027 21 22 23 24 25 26 27 28 44 1 INDEX OF PROCEEDING 2 PAGE 3 Upon commencing at 0910 3 4 ENBRIDGE PANEL 5 Pascale Duguay 7 6 Donald Small 7 7 Frank Brennan 8 8 Robert Bourke 8 9 Upon concluding at 1027 43 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28