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HomeMy WebLinkAboutROS1122A.txt 1 BOISE, IDAHO, TUESDAY, NOVEMBER 22, 1994, 2:15 P. M. 2 3 4 COMMISSIONER MILLER: We'll go on the 5 record. I had made a previous commitment for about 6 15 minutes at 3:00 o'clock; so we'll have to take a little 7 recess right at 3:00 o'clock for 15 minutes, and in 8 addition to that, other commitments mean that we really 9 can't go past 5:00 o'clock tonight; so we're going to have 10 to finish this hearing by 5:00 o'clock, if possible. 11 MR. FELL: Our people from Salt Lake City 12 have a flight at 4:55. It makes it real tough for them to 13 go past 4:15. 14 COMMISSIONER MILLER: Well, let's shoot for 15 a 4:15 completion and planning on a 15-minute recess at 16 3:00 o'clock. 17 Mr. Orndorff. 18 MR. ORNDORFF: Thank you, Mr. Chairman. I'd 19 like to introduce two new exhibits, Exhibits, I believe 20 it's, 82 and 83. 21 (Ms. Orndorff distributing documents.) 22 23 24 25 477 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 RONALD D. BLENDU, 2 recalled as a rebuttal witness at the instance of Rosebud 3 Enterprises, Inc., having been previously duly sworn, 4 resumed the stand and was further examined and testified 5 as follows: 6 7 DIRECT EXAMINATION 8 9 BY MR. ORNDORFF: (Continued) 10 Q Mr. Blendu, maybe you could tell us if you 11 recognize first Exhibit C, Page 1 of 1. 12 A I recognize that. 13 Q Can you tell us what that is? 14 A It's a sketch I made off of the other sketch 15 that you just handed out as a result of discussions 16 between myself, Mr. Lowe of PacifiCorp, and Mr. Witbeck of 17 Utah Power & Light, the regional engineer. 18 Q And maybe you could now tell us what 19 Exhibit B, Page 1 of 1 is. 20 A Exhibit B, Page 1 of 1, is a sketch of the 21 PacifiCorp transmission system in the Arco area that 22 Mr. Witbeck drew on the back of a napkin for me at lunch 23 as he described what the interconnect situation was in 24 lieu of the situation we thought existed prior to our 25 arrival at the site. 478 CSB REPORTING BLENDU (Di-Reb) Wilder, Idaho 83676 Rosebud Enterprises 1 MR. ORNDORFF: I would propose marking 2 Exhibit C, Page 1 of 1, as Exhibit 82 and Exhibit B, 3 Page 1 of 1, as Exhibit 83. 4 (Rosebud Enterprises, Inc. Exhibit 5 Nos. 82 & 83 were marked for identification.) 6 Q BY MR. ORNDORFF: Now, Mr. Blendu, 7 Mr. Witbeck, is he a Pacific Power employee? 8 A The card I have says he is a Utah Power & 9 Light regional engineer for Idaho out of Rexburg. 10 Q Now, with the benefit of these two exhibits, 11 can you relate these to Exhibit 127 which I believe was 12 sponsored by PacifiCorp this morning and tell us how you 13 understood the transmission situation at Arco? 14 A The Exhibit 127 that was put in this morning 15 differs somewhat from what was explained to me in Arco and 16 it differs somewhat from what I observed and it's a little 17 bit misleading in the way it's represented. For example, 18 when we toured the site, there is only one Arco 19 substation. Exhibit 127 would tend to cause one to 20 conclude there's two. If you look at my sketch where I 21 took the information from Mr. Witbeck, I attempted to 22 characterize it as there's a substation in Arco and 23 there's a switch from the Utah Power & Light that 24 basically keeps them separated and off line from supplying 25 power to Lost River. 479 CSB REPORTING BLENDU (Di-Reb) Wilder, Idaho 83676 Rosebud Enterprises 1 As it was explained to me, there's a 38 2 megawatt rated 69 kV line that's used for backup purposes 3 only out of the Scoville substation owned by Idaho Power. 4 It's normally not used, only in emergency, at which time 5 they close the switch. The Exhibit 127 also differs from 6 what Mr. Witbeck told me in that -- so if you'll bear with 7 me, let's just draw a box around the Arco and the Lost 8 River substation and assume that's one substation. To 9 make Exhibit 127 a little bit more accurate, I put two 10 miles between the proposed Rosebud site and the Arco 11 substation where it says the PacifiCorp has a sub. I put 12 about two miles between the proposed site and PacifiCorp's 13 230 kV line. There's about ten miles of 230 kV line 14 Mr. Witbeck explained to me that was owned exclusively by 15 BPA. Exhibit 127 would cause one to conclude that it's 16 jointly owned by BPA and Lost River; so I have no 17 information that the Lost River REA owns any 230 kV 18 transmission system. 19 From what we observed, about three miles 20 south of town, previously when we looked at the site, we'd 21 see the main PP&L line -- excuse me, PacifiCorp line -- 22 coming in towards the Arco sub and so when we previously 23 looked at the site, one would conclude that that continued 24 all the way to the Arco sub. In reality, what Mr. Witbeck 25 described is the line actually continued ten miles further 480 CSB REPORTING BLENDU (Di-Reb) Wilder, Idaho 83676 Rosebud Enterprises 1 upstream and tied into the Lost River substation at 2 Moore. 3 Exhibit 127 is not clear to me whether 4 PacifiCorp is now indicating -- it has an arrow to the 5 right saying Moore is somewhere off someplace; so it's not 6 clear to me whether PacifiCorp is now indicating that that 7 230 kV is jointly owned by BPA and Lost River and going 8 into the Arco substation or if that's really where they 9 say Lost River/BPA 230/69 kV, if they're indicating that 10 as a jointly-owned substation between Lost River and BPA 11 at Moore. If that's the case, then where there's a 69 kV 12 connecting the Lost River at Arco with the Lost River/BPA, 13 that's about a ten-mile run. If that's not the case and 14 they're indicating that BPA goes into the Arco substation, 15 then that whole system would be one substation as near as 16 I can tell. 17 What was surprising to us from the 18 information we had is that we could hook in at Arco to a 19 69 kV and where it was characterized as PacifiCorp's 69 kV 20 system. What Mr. Witbeck explained to me on his drawing 21 is basically that system was only a 69 kV line 20 miles 22 long between Idaho Power's INEL station, which they claim 23 is all, or at least it's indicated on here is all, owned 24 by Idaho Power and the Arco substation and that I'd have 25 to find a way to get out of Scoville. 481 CSB REPORTING BLENDU (Di-Reb) Wilder, Idaho 83676 Rosebud Enterprises 1 The 230 kV line that terminates as a direct 2 termination point, it says the Lost River REA substation. 3 It says a 230 kV line from Darlington terminated and 4 interconnected with PacifiCorp's 230 kV system in a Lost 5 River substation. What was being referred to this time 6 was the Lost River substation at Arco because none of the 7 discussions or any drawings showed any PacifiCorp 8 ownership beyond the Arco sub; so the information we had 9 said PacifiCorp came into Arco and interconnected, their 10 230 kV system interconnected, at Arco or at least some 11 Lost River substation. Even if one wanted to conclude 12 that there's a little fuzziness in the letter, they 13 indicated they interconnected with PacifiCorp 230 kV lines 14 in the area. 15 When we got there, as I mentioned before, 16 the two-mile line between, if you look at Exhibit 127, 17 between the Arco sub and the Rosebud proposed site was 18 actually about a 12.5 kV distribution line that went right 19 down alongside our property site. We looked at that 20 previously. We concluded worst case we would have to do 21 is replace that 12.5 kV line, give new distribution to the 22 area on the length of that line and then over-build that 23 with the higher voltage that we needed to hook into 24 PacifiCorp. 25 When we got there and saw that PacifiCorp 482 CSB REPORTING BLENDU (Di-Reb) Wilder, Idaho 83676 Rosebud Enterprises 1 didn't go to any substation, they just pointed to a board 2 or something that was up on the lines and said that's 3 where we stop, the only way we could have gotten there is 4 to head cross country through farmland to get some 5 easements and things like that and build a 2-$3 million 6 substation out in the middle of a right of way. 7 The second option we were presented to was, 8 well, we're rated for 38 megawatts on this line, but we 9 only run three on it; so we don't know what it's good for 10 it anymore, but we certainly wouldn't let you put 40; so 11 you could build us 20 miles of 69 kV, go down to Scoville, 12 make whatever arrangements you need to make with Idaho 13 Power, and then come off on 138 kV and send it over to us 14 in Antelope. 15 Both of those options required wheeling 16 arrangements, pricing far above and beyond what we had 17 been led to believe we could get to. As our discussion 18 progressed, Pacific indicated, you know, don't care where 19 you put the power out here in the east as far as these 20 interconnects go, and we batted that around a bit that no 21 place was good and one was as good as another, and from 22 that, I indicated that neither of these options, the 23 230 kV interconnect and a substantial substation, running 24 20 miles of line, was palatable to us and we would go back 25 and rethink our location, which is what we did. 483 CSB REPORTING BLENDU (Di-Reb) Wilder, Idaho 83676 Rosebud Enterprises 1 Q Now, in originally siting the plant at Arco, 2 did you rely on the information in Exhibit 16? 3 A Exhibit 16 is the May 15th letter? 4 Q Yes, 1990. 5 A The May 15th, 1990, letter, I heavily relied 6 on the information that PacifiCorp had both 230 kV 7 interconnection capabilities and 69 kV capabilities in the 8 Arco area. 9 Q Mr. Blendu, in your experience, does a 10 utility normally know the structure of its system? 11 A I would have to say that that would be a 12 reasonable expectation that, yes, they would normally know 13 what their ownership is. 14 Q Okay, Mr. Blendu, would you turn now to 15 Exhibit 69? 16 A Yes. 17 Q And in that second paragraph of Exhibit 69, 18 you've heard some discussion about what would be the 19 second and third sentence. Would you tell us the 20 difference between interconnection as you understand it 21 and integration and what those two studies might be? 22 A Yes, I can, and I recall very vividly the 23 discussions between you and I that led up to this and I 24 heard the testimony earlier and I was somewhat astounded 25 that there was confusion between the two, and as a result, 484 CSB REPORTING BLENDU (Di-Reb) Wilder, Idaho 83676 Rosebud Enterprises 1 while we were on break, I called three separate electrical 2 engineers to see if it was reasonable to expect people to 3 know the difference, and while people could understand, 4 you know, there may be cause for question, traditionally, 5 most people would understand an interconnect study that 6 this letter says Rosebud would pay for to mean Rosebud 7 would pay for the hardware and equipment and the cost of 8 going in and making an interconnection. 9 What Rosebud was objecting to in this 10 particular letter was a system integration study where you 11 do massive load flow studies and line losses, shifts in 12 power phases which could be a study of gigantic 13 proportions. We just recently received some of that kind 14 of material in terms of load flow studies from PacifiCorp 15 last week and it's a pretty massive undertaking. I think 16 that's what we were objecting we did not want to get 17 into. 18 What's particularly dumbfounding is that if 19 someone says I'll pay for the interconnect, but I won't 20 pay for system integration studies that no one would even 21 call if they didn't know the difference and ask if there 22 is a difference. 23 MR. ORNDORFF: Thank you, Mr. Blendu. I 24 have no more questions. 25 COMMISSIONER MILLER: Cross-exam. 485 CSB REPORTING BLENDU (Di-Reb) Wilder, Idaho 83676 Rosebud Enterprises 1 CROSS-EXAMINATION 2 3 BY MR. FELL: 4 Q Mr. Blendu, would you please turn to 5 Exhibit 16? 6 A Yes. 7 Q And would you also place before you 8 Exhibit No. 127? Would you please explain what it is in 9 the letter of May 15, 1990, the Exhibit 16, that is 10 incorrect? 11 A The May 15th letter, when we were proposing 12 a Darlington project, we were proposing hooking into a BPA 13 line that went near Darlington and running that power in 14 through BPA to Goshen. The May 15th letter says we don't 15 go into Goshen, we go into a Lost River substation which 16 is a point of interconnection with PacifiCorp's 230 kV 17 system. I took that to mean that at the Lost River/BPA 18 sub, and in further discussions with PacifiCorp, we were 19 meaning the Arco substation, not the one in Moore -- 20 Q Excuse me. 21 A Could I finish? 22 Q No, I'm sorry, but -- 23 MR. ORNDORFF: You're interrupting the 24 witness, I object. 25 COMMISSIONER MILLER: Mr. Orndorff, this is 486 CSB REPORTING BLENDU (X-Reb) Wilder, Idaho 83676 Rosebud Enterprises 1 the fourth time I've suggested that if you have problems 2 you address them to the Chair and not bicker with opposing 3 counsel. 4 MR. ORNDORFF: I'm sorry, it's been a long 5 day. 6 COMMISSIONER MILLER: Now, what's the 7 problem, Mr. Fell? 8 MR. FELL: The problem is that the witness 9 was going a little fast for me and I was going to have to 10 ask him to go back and do this again, because when he 11 started switching substations, I got lost. I wanted him 12 to slow down on that. 13 THE WITNESS: Okay, I'm sorry. The May 15th 14 letter indicated PacifiCorp did not interconnect with BPA 15 at Goshen, but in lieu, interconnected 230 kV 16 interconnection at the Lost River substation, and that 17 refers to BPA's line coming down out of Darlington, Idaho, 18 and the line running through Darlington interconnecting 19 with PacifiCorp at a Lost River substation. 20 Q Very well. Now, what is it in the letter of 21 May 15, 1990, that is incorrect? 22 A Well, one, PacifiCorp at least in the area 23 of Arco or any of the Lost River substations doesn't come 24 anywhere near the Lost River REA at Moore and it certainly 25 is not an interconnection point at the other Lost River 487 CSB REPORTING BLENDU (X-Reb) Wilder, Idaho 83676 Rosebud Enterprises 1 substation at Arco. 2 Q Let's take what is shown on Exhibit 127 as 3 Lost River/BPA, if that is intended to be also what you 4 describe as the Moore substation. 5 A Yes, and we put ten miles under 230 kV at my 6 suggestion. 7 Q All right. Now,, you're saying that the 8 letter is wrong because BPA has ten miles ownership of the 9 230 kV line? 10 A It says it terminates at the Lost River 11 substation, terminates, ends, not continues for ten miles, 12 and it says it's a point of interconnection, which means 13 it could be a point of interconnection for me as well at 14 that substation with PacifiCorp. 15 Q Now, it says that the BPA 230 kV line 16 terminates at the Lost River substation and that's the one 17 coming from Darlington? 18 A That's what this letter says. It says 19 there's a line coming from Darlington that terminates at 20 the Lost River substation, a point of interconnection with 21 PacifiCorp's 230 kV system. 22 Q Is it that last clause that you think is 23 wrong? 24 A Certainly. 25 Q Is it your position, then, that that is the 488 CSB REPORTING BLENDU (X-Reb) Wilder, Idaho 83676 Rosebud Enterprises 1 misleading information that caused you to locate at Arco? 2 A It's one of them. If you go down to the 3 next line further, it says I could also run a new 69 kV 4 line down from Darlington and interconnect into 5 PacifiCorp's 69 kV system, and when we get there, as near 6 as I can tell, the system consisted of a 20-mile line 7 between Scoville and Arco. 8 Q Let me just have a minute so I can read what 9 this says. 10 A Okay. 11 Q It does say that that is an option, but I'm 12 trying to decide what part of this caused you somehow to 13 locate in Arco without any further investigation of the 14 implications of your location. 15 A Well, I wouldn't assume there was no further 16 investigation, okay? 17 Q Let me say, then, that no further 18 investigation of the transmission system. 19 A I wouldn't say that, okay? 20 Q Did you have any further communications with 21 PacifiCorp about your decision to relocate? 22 A As I understand the earlier testimony, we're 23 distinguishing that we did not relocate Darlington to 24 Arco, okay. I'm understanding that when we talked to 25 PacifiCorp about a project at Darlington, they sent a 489 CSB REPORTING BLENDU (X-Reb) Wilder, Idaho 83676 Rosebud Enterprises 1 letter back that said I have interconnection capabilities 2 into my 69 kV system at Arco and I have a termination into 3 the Lost River substation and, again, at the discussions 4 that also went on at the time and the transmission 5 drawings show PacifiCorp ownership into Arco and they show 6 no PacifiCorp ownership beyond Arco up to the Moore 7 substation; so it's pretty hard to conclude that that's 8 the one that was being referred to, but I assume that you 9 could make that interpretation. 10 Based on that letter with regards to 11 Darlington, yes, I concluded that we could hook directly 12 in to PacifiCorp either on 69 kV/230 kV, avoid wheeling 13 agreements, avoid substantial transmission line rebuilding 14 other than the two miles of interconnection line from our 15 proposed site to the Arco sub based on that letter. 16 Q Your answer, just to give you some 17 background on this, your answer to me is mixing 18 interconnecting at the Arco 69 kV sub with interconnecting 19 at the Lost River 230 kV sub. I just want to -- 20 MR. ORNDORFF: Excuse me, I'd like to 21 object. He's arguing with the witness and he's going over 22 and over it and I don't think we're going anyplace fast. 23 COMMISSIONER MILLER: Why don't we see what 24 the question actually is and then if you have an 25 objection, you could state it. 490 CSB REPORTING BLENDU (X-Reb) Wilder, Idaho 83676 Rosebud Enterprises 1 Q BY MR. FELL: Speaking only as to the 230 2 Lost River sub, the only difference between the letter of 3 May 15, 1990, and what you know now, if I understand this 4 correctly, is that ten miles of that 230 kV line going 5 into the sub are owned by BPA; is that correct? 6 A That's not correct. 7 Q Staying on the 230 kV line, between the 8 proposed Rosebud site and the Lost River substation, what 9 else is different? 10 A What's different is when I met the 11 PacifiCorp people in the morning, they said our drawings 12 are wrong, our 230 kV system does not go into the Arco 13 substation, and while, I'll repeat, one can conclude that 14 this is referring to the Lost River substation at Moore, 15 that is not consistent with the discussions, it's not 16 consistent with the understanding and it's not consistent 17 with the discussion of the PacifiCorp people when we 18 scheduled the trip there. We were all under the 19 impression that PacifiCorp had a 230 kV interconnect at 20 Arco. 21 Q When you say "at Arco," what do you mean "at 22 Arco"? 23 A At the Arco substation. 24 Q You're saying that PacifiCorp believed its 25 Arco 69 kV substation was a 230 substation? 491 CSB REPORTING BLENDU (X-Reb) Wilder, Idaho 83676 Rosebud Enterprises 1 A Yes. 2 MR. FELL: Well, there's no reason to go 3 further on this, then. 4 THE WITNESS: I think it's amusing, too. 5 MR. FELL: No further questions. 6 COMMISSIONER MILLER: Redirect, 7 Mr. Orndorff. 8 MR. ORNDORFF: I have nothing. 9 COMMISSIONER MILLER: Sir, thank you once 10 again for your help. 11 (The witness left the stand.) 12 MR. ORNDORFF: Can I ask to have 13 Mr. Blendu permanently excused now? 14 COMMISSIONER MILLER: You can be permanently 15 excused, subject to call. 16 MR. ORNDORFF: I don't expect to call, 17 though. 18 COMMISSIONER MILLER: All right, Mr. Fell, 19 thank you for accommodating that out-of-order witness. 20 We'll go back to your presentation now. 21 MR. FELL: PacifiCorp calls John Lowe. 22 23 24 25 492 CSB REPORTING BLENDU (X-Reb) Wilder, Idaho 83676 Rosebud Enterprises 1 JOHN R. LOWE, 2 produced as a witness at the instance of PacifiCorp, 3 having been first duly sworn, was examined and testified 4 as follows: 5 6 DIRECT EXAMINATION 7 8 BY MR. FELL: 9 Q Mr. Lowe, would you please state your name 10 for the record and your position with PacifiCorp? 11 A Yes, my name is John R. Lowe. I'm a member 12 of the resource acquisition staff. 13 Q Mr. Lowe, did you attend a meeting in Boise 14 with Rosebud on December 30, 1993? 15 A Yes, I did. 16 Q What was the purpose of that meeting, 17 Mr. Lowe? 18 A The primary purpose was to discuss the 19 contract, comments from, I believe it was, October by 20 Rosebud, Rosebud's comments. 21 Q In their October, 1993 -- 22 A That's correct. 23 Q And had that meeting been scheduled a week 24 or so earlier originally? 25 A My recollection was that it had been and I 493 CSB REPORTING LOWE (Di) Wilder, Idaho 83676 PacifiCorp 1 believe that I was in a skiing accident and delayed the 2 meeting for some week or two. 3 Q You have before you what we have marked as 4 130. Would you please explain what this exhibit is? 5 A Notes from the December 30th discussion 6 between myself, Mr. Fell, Mr. Orndorff, Mr. Roberts, and 7 Mr. Blendu, and Dr. Slaughter. 8 MR. FELL: Mr. Chairman, to keep things 9 absolutely clear, on the third page of that document, 10 there are two lines in the margin on the right, those were 11 put there later. They're not part of the meeting notes, 12 so that we are absolutely correct about that. 13 Q BY MR. FELL: Mr. Lowe, do these minutes of 14 that meeting fairly reflect what occurred at the meeting 15 from your perspective? 16 A I'd have to study them. I've only looked at 17 them very briefly earlier today. That's the first time 18 I've seen them for a little while. They appear to 19 generally reflect what I recall about the meeting. 20 MR. ORNDORFF: Is now the appropriate time 21 to renew my objection, Mr. Chairman? 22 MR. FELL: I think if you're going to 23 object, yes. Excuse me, Mr. Chairman. 24 COMMISSIONER MILLER: No further foundation 25 that you need to lay? 494 CSB REPORTING LOWE (Di) Wilder, Idaho 83676 PacifiCorp 1 MR. FELL: Mr. Chairman, I have two ways of 2 proceeding. One is to introduce the meeting notes. The 3 other would be to ask Mr. Lowe to explain what transpired 4 in that meeting and in doing that, he is allowed under the 5 rules to refresh his recollection by using the notes; so 6 he would be able to go through this item by item. 7 MR. ORNDORFF: Mr. Chairman, I will object 8 to both if that's where Mr. Fell is going. I presume, 9 although he hasn't told us, that if he goes the second 10 way, that's more supplemental direct testimony. This 11 record is -- you know, we all worked very hard to get 12 supplemental direct on and there aren't even any exhibits 13 that he has. I have introduced the contract draft that 14 was the discussion of the document, the comments that were 15 put in, and Mr. Fell's notes, while they're interesting, 16 for putting them into the record as to what was said and 17 having Mr. Lowe sponsor them who has just refreshed his 18 memory in three minutes seems a bit outrageous. 19 We have in the record the contract. We have 20 in the record the fact that there was a meeting. I'm not 21 sure that it lends anything to the science to put some 22 hearsay information in or to have Mr. Lowe give us his 23 spontaneous recollections of something that occurred over 24 a year ago, is it a year, yes, getting close to a year, 25 and if the Commission wants to entertain this testimony, I 495 CSB REPORTING LOWE (Di) Wilder, Idaho 83676 PacifiCorp 1 obviously will want Mr. Blendu to be able to respond. I 2 had no idea this was going to happen when I entered the 3 stipulation. I guess that's the danger of entering a 4 stipulation. I can have Mr. Roberts respond if you'd 5 like, but I obviously will want somebody and the right to 6 offer rebuttal. 7 MR. FELL: Mr. Chairman. 8 COMMISSIONER MILLER: Mr. Fell. 9 MR. FELL: The genesis of this is 10 Mr. Orndorff's questioning of Mr. Duvall about 11 specifically how the Company responded to his October, 12 1993 contract draft and comments. Mr. Duvall said this 13 meeting occurred, Mr. Duvall said these minutes existed. 14 We have explained how we responded, but this is the piece 15 that Mr. Orndorff apparently does not want in the record, 16 but this meeting was in response to that contract draft. 17 COMMISSIONER MILLER: It appears to me that 18 there is a general acknowledgment and no dispute the 19 meeting did occur, the fact of a meeting is established, 20 that seems to be clear; so I wonder if I could ask, what 21 is it in this document that is relevant to some other 22 issue of fact that remains disputed? 23 MR. FELL: The other issue, Mr. Chairman, 24 that remains disputed is the statement on the third page 25 of the minute notes, of the meeting notes, that says, that 496 CSB REPORTING LOWE (Di) Wilder, Idaho 83676 PacifiCorp 1 attributes to Mr. Lowe, "We've moved through the rate 2 issues, we will need to quickly move to interconnection 3 study," and then a second note, "Rosebud says: We need to 4 get past the rate issue before we start spending money." 5 COMMISSIONER MILLER: So you would propose 6 to prove in one manner or another that a Rosebud 7 representative said those words or words to that effect at 8 that time; is that what we're boiling down to? 9 MR. FELL: That's correct. This is 10 corroboration of our point that they were not ready to 11 spend the money on the interconnection study. 12 COMMISSIONER MILLER: All right, I think 13 we're getting at least focused in on the relevance here, 14 Mr. Orndorff. Putting aside hearsay and other problems, 15 is there a dispute with respect to that or its relevance? 16 MR. ORNDORFF: Absolutely, there's a 17 dispute. That's a characterization of PacifiCorp's 18 attorney as to spending money without any specificity. 19 We're obviously spending buckets of money in this 20 proceeding and have spent buckets of money trying to get a 21 contract and it's a little bit much to imagine that we 22 aren't spending money trying to move this project 23 forward. 24 Now, I don't know what he was referring to 25 when he wrote this note. I definitely agree that it says 497 CSB REPORTING LOWE (Di) Wilder, Idaho 83676 PacifiCorp 1 that, but, then again, that isn't what happened and I will 2 offer testimony. You know, if the Commission wants to 3 entertain that quality of evidence, then I certainly will 4 bring forth rebuttal testimony what that really meant and 5 we can get into whose note says what and whose 6 recollection -- what is relevant is what I think the 7 Chairman earlier said today, we want to look at what 8 happened and why and look at events and not get into 9 argumentative-type testimony. 10 COMMISSIONER MILLER: Well, we've been 11 plagued throughout this case with the problem of what 12 happens when lawyers are negotiators and then litigators 13 and then face the rule they can't be witnesses. Let's 14 take a short break here. 15 (Off the record discussion.) 16 COMMISSIONER MILLER: Well, the Commission 17 will more fully set forth the basis for its ruling on this 18 matter, if necessary, in a final order, but just by way of 19 indication, it does appear that the document itself would 20 constitute hearsay and even though a document that is 21 otherwise hearsay can be admitted if it's a recorded 22 recollection of events that previously occurred, 23 generally, the recorded recollection should be by the -- 24 the witness sponsoring it should be the witness who wrote 25 it, although there is a provision that the document can be 498 CSB REPORTING LOWE (Di) Wilder, Idaho 83676 PacifiCorp 1 adopted by another person, although Mr. Lowe has testified 2 that he has only a general familiarity with it but seems 3 generally to be what he thinks happened, although his 4 degree of endorsement of the document was so vague that we 5 think it would probably be best not to put this document 6 in the record. 7 MR. FELL: That's fine. I think we'll rely 8 on the record as it stands, then, without this and I have 9 no further questions. 10 COMMISSIONER MILLER: Very good. Thank 11 you. Mr. Lowe, you can be excused. Thank you for your 12 attempted help. 13 (The witness left the stand.) 14 MR. ERIKSSON: Our next witness is 15 Dr. Weaver. 16 17 18 19 20 21 22 23 24 25 499 CSB REPORTING LOWE (Di) Wilder, Idaho 83676 PacifiCorp 1 RODGER WEAVER, 2 produced as a witness at the instance of PacifiCorp, 3 having been first duly sworn, was examined and testified 4 as follows: 5 6 DIRECT EXAMINATION 7 8 BY MR. ERIKSSON: 9 Q Dr. Weaver, will you please state your name 10 and business address? 11 A My name is Roger Weaver. My business 12 address is 825 N.E. Multnomah, Portland, Oregon. 13 Q And your position with PacifiCorp? 14 A My position is the power systems regulation 15 manager. 16 Q And have you had -- have you prepared and 17 caused to be filed direct testimony in this case 18 consisting of 26 pages and four exhibits identified as 19 Exhibits 112 through 115? 20 A Yes, I have. 21 Q Do you have any corrections to the testimony 22 or exhibits? 23 A No. 24 Q If I asked you the same questions as are 25 contained in your testimony today, would your answers be 500 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 the same? 2 A Yes, they would. 3 MR. ERIKSSON: I'd ask that Dr. Weaver's 4 direct testimony be spread on the record and the attached 5 exhibits be identified as Exhibits 112 through 115. 6 COMMISSIONER MILLER: All right, if there's 7 no objection, it will be so ordered. 8 (The following prefiled testimony of 9 Dr. Rodger Weaver is spread upon the record.) 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 501 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 Q Please state your name, business address and 2 present position with PacifiCorp (the Company). 3 A My name is Rodger Weaver. My business 4 address is 825 NE Multnomah, Suite 625, Portland, Oregon 5 97232. My present position is Power System Regulation 6 Manager. 7 Q Please briefly describe your education and 8 business experience. 9 A I received an undergraduate degree in 10 Economics and a Ph.D. in Economics from the University of 11 Utah. I worked for the Public Service Commission of Utah 12 from 1984 - 1987 as a Senior Economist, and the Utah 13 Division of Public Utilities from 1987 - 1992 as a Senior 14 Economist. In 1992 I began working for PacifiCorp as a 15 Manager of Power System Regulation. 16 Q Please describe your current duties. 17 A I am responsible for the direction and 18 coordination of net power cost and related analyses. In 19 addition, I represent the Company on power resource issues 20 and provide information to various regulatory commissions. 21 Q What is the purpose of your testimony? 22 A The purpose of my testimony is to explain 23 how the Company computed its adjustment to the currently 24 approved avoided costs to produce the prices included in 25 its July 11, 1994, proposal to Rosebud. This price 502 Weaver Di PacifiCorp 1 proposal is structured as separate prices for each of 2 three products to be provided by 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 503 Weaver Di PacifiCorp 1 Rosebud: (1) capacity, (2) on-peak energy, and (3) 2 off-peak energy. 3 Q What avoided costs did you use as the 4 starting point for your calculations? 5 A I used those in effect prior to January 14, 6 1994. The Company's position is that Rosebud's project 7 had not been developed sufficiently to justify a finding 8 that Rosebud is entitled to priced based on those avoided 9 costs. Rosebud's project should be priced based on the 10 avoided costs to be established by the Commission in the 11 current avoided cost case. 12 The July 11, 1994, pricing proposal illustrates the 13 appropriate adjustments to the SAR-based rates for the 14 Rosebud project. It does not waive the Company's 15 objection to Rosebud's grandfathering claim. 16 Q Please explain how the Company's proposed 17 prices were calculated. 18 A The Company took its published SAR-based 19 avoided costs as the starting point and broke the capacity 20 and energy elements out separately. It then calculated 21 on- and off-peak energy prices based on values contained 22 in the currently approved SAR-based avoided costs. As 23 explained by Mr. Morris and me, the different pricing for 24 off-peak energy reflects the energy costs that Rosebud 25 would allow the Company to avoid. These adjustments implement the "ability to schedule" line item 504 Weaver Di PacifiCorp 1 upon which the Commission allows negotiation. Ability to 2 schedule refers to the utility's ability to shape 3 operation of the facility to meet system load shape 4 requirements, i.e., to dispatch the facility. 5 The Company's proposal assumes that the Company 6 will not have the ability to schedule Rosebud's operation. 7 Without the ability to schedule Rosebud's operation to 8 match system requirements, it is necessary to structure 9 the purchase prices to reflect the system costs that would 10 be avoided. This pricing structure allows the Company to 11 take Rosebud's output into its system while leaving its 12 customers financially indifferent to the source of the 13 power; i.e., to neither impose additional cost nor award 14 customers a windfall cost reduction. 15 Q Are there any other advantages to the 16 multi-part pricing structure in the Rosebud context? 17 A Yes. As Mr. Ramisch explains, we have been 18 unable to get from Rosebud a clear understanding of its 19 operating plans and expectations. A clear understanding 20 of plant operations would be necessary to develop 21 all-energy pricing that even approximately matches the 22 costs the project would allow the Company to avoid. Use 23 of multi-part pricing removes this uncertainty as a 24 Company concern. The Company would pay for the products 25 as Rosebud delivers them at prices reflective of the costs avoided. Operational concerns become the sole 505 Weaver Di PacifiCorp 1 responsibility and concern of the project with no 2 possibility of imposition of unintended and unjustified 3 costs on the Company and its customers. 4 Q Please discuss the meaning of the term 5 dispatchability and its significance to the determination 6 of published rates. 7 A Dispatchability refers to whether the 8 utility has control over when and to what extent the 9 resource is run -- resources are usually dispatched in 10 lowest-running cost first or economic merit order. 11 Dispatchability does not, in general, refer to the 12 specific technological characteristics, construction costs 13 or realized capacity factors of generating resources. In 14 some instances, however, technology can limit 15 dispatchability. Wind, traditional solar and some hydro 16 resources must operate when the primary energy source is 17 available and cannot be run at other times. 18 Utility-owned resources will typically be 19 dispatchable. This is true of base-loaded units such as 20 the Company's Dave Johnson plant, which is operated at 21 over a 90 percent capacity factor, through swing units 22 such as Gadsby at just under 50 percent and peaking 23 resources such as the Southern California Edison (SCE) 24 winter capacity purchase, which has been operated at a 25 less than 10 percent capacity factor. All these resources 506 Weaver Di PacifiCorp 1 are dispatchable. They represent different technologies 2 and both their construction and their operating costs vary 3 widely. Their differing capacity factors result 4 5 / 6 7 / 8 9 / 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 507 Weaver Di PacifiCorp 1 from the Company's economic dispatch decisions as to how 2 much they should be operated. Thus, it is the ability to 3 control a facility that determines whether it is 4 dispatchable. On this basis, power purchases can be 5 dispatchable, depending on the terms of the agreement. 6 For example, the SCE winter capacity contract is a 7 dispatchable purchase. Traditional QFs, which are run at 8 the convenience of the project and not the Company, are 9 classic non-dispatchable resources whether they are high 10 load factor cogeneration resources or low load factor 11 seasonal irrigation based hydro projects. It is important 12 to understand that, contrary to the view apparently taken 13 by Dr. Slaughter, a base load resource may well be 14 dispatchable. In fact, as indicated, all of the Company's 15 base loaded units are dispatchable and are operated at 16 high capacity factors because their low incremental costs 17 to the system lead the Company's operators to run them as 18 much as possible. 19 Q How is the concept of dispatchability 20 reflected in the Company's Rosebud pricing proposal? 21 A The Company proposes to price Rosebud's 22 output to reflect the dispatchable nature of the Powder 23 River coal SAR costs as if the SAR were dispatchable. To 24 do so, Rosebud's output is broken down into three 25 products. The first is capacity defined in standard 508 Weaver Di PacifiCorp 1 electric industry terms as the ability of the plant to 2 produce power at the time it is most needed by 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 509 Weaver Di PacifiCorp 1 the utility. It is measured in watts and is priced on the 2 basis of dollars per kW per month ($/kW-mo). The second 3 product is energy delivered during on-peak hours and is 4 priced at the fully loaded energy cost of the SAR. This 5 product is measured in kilowatt hours (kWh) and priced on 6 the basis of mills per kWh. This product represents the 7 value of SAR-produced energy to the system when use of the 8 output is not constrained. The third product is energy 9 delivered during off-peak hours, also measured in kWh and 10 priced in mills per kWh. This product is priced in terms 11 of the SAR running cost the Company can avoid by accepting 12 Rosebud energy into the system during times when its use 13 is constrained. This approach mimics the use the Company 14 would be able to make of its existing system if a new 15 resource were added in Idaho, Wyoming or Utah. 16 Q Can the value of dispatchability to the 17 system be reflected in one-part or energy-only prices? 18 A No. Any one-part price must necessarily be 19 based on anticipated, rather than realized, project 20 performance and timing deliveries. A one-part price will 21 result in the same payment for each kilowatt hour provided 22 by the QF regardless of the value of the power to the 23 utility at the time of delivery. In addition, a one-part 24 price also produces payment at higher than avoided costs 25 any time the QF operates at a higher capacity factor than that used in 510 Weaver Di PacifiCorp 1 computing the price. For example, assume a QF paid 2 current approved all-energy prices operates at a capacity 3 factor higher than 75%. It would be paid more than the 4 avoided SAR capital costs since the SAR rates are based on 5 a 75% capacity factor. The multi-part pricing approach 6 automatically conforms payment for QF power to estimates 7 of actual costs avoided, and limits recovery of capital 8 costs to those which the QF actually allows the Company to 9 avoid. Note that in Case No. PPL-E-93-5/UPL-E-93-7 the 10 Commission staff recommends consideration of this pricing 11 approach as an alternative for large projects. Further, 12 the Commission approved separation of prices into capacity 13 and energy components in Order No. 25706. 14 Q Why does the Company price capacity at the 15 capital cost of a simple cycle combustion turbine (SCCT) 16 rather than at the full capital cost of the currently 17 approved SAR? 18 A SCCT technology is used because it is a 19 reasonable current estimate of the cost the Company would 20 have to incur in order to acquire an alternative resource 21 for meeting peak capacity needs. It is well recognized 22 that the capital costs associated with resources expected 23 to be base-loaded, such as the SAR, are properly allocated 24 between energy and capacity classifications. For example, 25 the National Association of Regulatory Utility 511 Weaver Di PacifiCorp 1 Commissioners (NARUC) in its 1991 Electric Utility Cost 2 Allocation Manual (Draft) states on page 53: 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 512 Weaver Di PacifiCorp 1 There is evidence that energy loads are a major determinant of production plant costs. Thus, 2 cost of service analysts may incorporate energy weighting into production plant [capital] costs. 3 4 Dr. Hethie S. Parmesano states the issue in terms more 5 directly related to avoided cost considerations in her 6 September 17, 1987, Public Utilities Fortnightly article, 7 "Avoided Cost Payments to Qualifying Facilities: Debate 8 Goes On": 9 ... a system planner can justify a high capital cost base-load unit only if the unit is expected 10 to run for many hours of the year and provide energy savings compared to producing that energy 11 with other resources. In fact, a least-cost resource plan should involve spending for demand 12 reasons no more than the per kilowatt cost of peaking resources. 13 14 The peaking resources Dr. Parmesano refers to in 15 the article are either SCCTs or capacity purchases 16 depending on circumstances. 17 Thus it is appropriate to assign peaking resource 18 costs to avoided capacity costs and the balance of capital 19 cost of plants expected to run at higher-than-peaking 20 capacity factors to energy costs. This is the approach 21 taken by the Company. 22 I would further point out that the Company's 23 avoided costs approved in Washington, Oregon, 24 California, Montana, Wyoming and Utah are all separate 25 capacity and energy rates 513 Weaver Di PacifiCorp 1 with the classification of capital costs between capacity 2 and energy done using the same peaking resource-based 3 method used in the Company's proposal to Rosebud. 4 Q Does this discussion impact the calculation 5 of avoided costs using the SAR method for smaller 6 projects? 7 A No. It is irrelevant when calculating 8 all-energy costs using the Commission's SAR spreadsheet 9 model. In that model, capital costs are spread over 10 energy production at the assumed capacity factor without 11 regard to energy vs. capacity classification of capital 12 cost. This calculation assumes use of the SAR output is 13 never constrained and that the SAR would run at the 14 assumed capacity factor. It does not account for 15 dispatchability to conform to the costs the QF would 16 actually allow the system to avoid. Only in negotiation 17 of contracts with projects above the Commission 18 established maximum size limit does the classification 19 issue play a role. 20 Q How does the Company's pricing proposal 21 implement these dispatchability considerations into an 22 adjustment from the SAR starting point? 23 A The Company's proposal as it was presented 24 to Rosebud appears as Exhibit 112. The first two pages of 25 the exhibit are the narrative description of the 514 Weaver Di PacifiCorp 1 procedure. The last page presents the actual 2 calculations. The spreadsheet uses exactly the same 3 calculations and data as approved in Order No. 23358 4 and corrected in Order No. 23429, except, of 5 6 / 7 8 / 9 10 / 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 515 Weaver Di PacifiCorp 1 course, it excludes the steps which convert to the all-energy 2 formulation. It computes the yearly tilted capital cost 3 for the SAR in Column (1) and converts this to a $/kW-mo 4 basis in Column (2). Column (3) computes annual capacity 5 cost using the same calculation procedures and inputs, but 6 applying them to the capital cost of a SCCT. Column (4) 7 then converts these to a kW-mo basis. This column is the 8 price proposed for capacity provided by the project. 9 Column (5) is the difference between Columns (2) 10 and (4) and is the portion of total SAR capital cost 11 classified as energy-related. Column (6) then converts 12 Column (5)'s $/kW-mo figures to a mills/kWh basis for 13 application to energy production. This conversion is 14 based on the 88% capacity factor provided by Rosebud. 15 Column (7) adds the annual non-adjustable O&M costs from 16 Order No. 25578. Column (8) is the sum of Columns (6) and 17 (7) and is the value of energy from the SAR when the 18 energy can be fully integrated into the system. This is 19 one of the two components of the price proposal for the 20 on-peak energy product. 21 Column (9) is the Adjustable Portion of the SAR 22 avoided costs. The value shown for 1994 is the Adjustable 23 Portion currently established by the Commission. As 24 indicated, the values shown for 1995 through 2018 are 25 illustrative only. They would be established year by 516 Weaver Di PacifiCorp 1 year using current Commission-established methods. In 2 the spreadsheet, they are 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 517 Weaver Di PacifiCorp 1 based on the 5.13 percent annual escalation rate used in 2 the -170 case. Column (9) is the price proposal for the 3 off-peak energy product. It is the SAR-based proxy for 4 the only cost which could be avoided during the off-peak 5 period; i.e., the running cost of existing eastside coal 6 resources. Column (9) is also the second of two 7 components of the price proposal for the on-peak energy 8 product. Note that the sum of Columns (8) and (9), shown 9 in Column (10), is the total proposed price for the 10 on-peak energy product. 11 Q Why should the energy produced by the 12 project be broken into on- and off-peak components with 13 different prices for each? 14 A This procedure is necessary to reflect 15 certain operational limitations on the system and their 16 implications for the SAR-based costs a QF would allow the 17 Company to avoid. As Mr. Morris explains in detail, the 18 Company has a limited ability to move power from its 19 eastside generation resources to its westside load 20 centers. This limitation imposes a constraint on the use 21 of those resources during the off-peak hours when the 22 eastside resources are used to meet westside requirements, 23 including return of BPA Capacity/Energy Exchange energy, 24 net of westside resources. The use of these existing 25 resources for this purpose is an important source of 518 Weaver Di PacifiCorp 1 efficiency in the operation of the Company's system. 2 However, this use is constrained by the limited 3 east-to-west transmission capacity described by 4 Mr. Morris. Thus, all the 5 6 / 7 8 / 9 10 / 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 519 Weaver Di PacifiCorp 1 costs that any added eastside generation would allow the 2 Company to avoid during off-peak hours are the running 3 costs of the existing low-running-cost resources. To base 4 eastside QF prices on these avoided costs, it is necessary 5 to identify off-peak energy as a separate product. 6 On-peak energy, on the other hand, is properly priced 7 based on the full cost of the avoidable resource, the SAR 8 in this case. 9 Q Can you describe the load/resource balances 10 in the east and west sides of the system during off-peak 11 hours? 12 A Yes. Exhibit 113 presents the off-peak 13 loads and the resources available to meet those loads on 14 the two sides of the system. The off-peak resource 15 availabilities are characteristic of actual resource 16 operation during off-peak hours. Coal resources are 17 operated at full capacity, purchases are reduced to 18 minimum contract requirements, and Company-owned hydro 19 resources are backed off to the extent possible in order 20 to preserve impounded water for use as a peaking resource 21 during heavy load hours. Westside off-peak load includes 22 return of energy to BPA in conjunction with the Company's 23 capacity purchase from BPA. 24 Q Please describe the BPA Capacity/Energy 25 Exchange. 520 Weaver Di PacifiCorp 1 A The BPA Capacity/Energy Exchange contract 2 represents approximately one-third of PacifiCorp's west 3 side capacity requirement. Under the exchange, BPA 4 provides up to 1,100 MW of capacity is provided to 5 PacifiCorp during on-peak hours; 6 7 / 8 9 / 10 11 / 12 13 14 15 16 17 18 19 20 21 22 23 24 25 521 Weaver Di PacifiCorp 1 this is by far BPA's largest capacity exchange contract 2 with a utility. In exchange, the Company returns the 3 equivalent amount of energy to BPA during off-peak hours. 4 In this way, PacifiCorp's low cost off-peak coal-fired 5 energy costs can be "shaped" into low cost capacity. The 6 energy delivered to BPA allows BPA to effectively store 7 energy in the Federal hydro system. 8 The capacity exchange contract is important to the 9 efficient operation of the Company's total complement of 10 resources. Eighty percent of the Company's energy is 11 produced from base loaded coal-fired units. The capacity 12 exchange contract allows the Company to shape this low 13 cost energy into the peak load hours, thereby reducing the 14 need to acquire higher cost peaking energy. This method 15 of system operation is unique to PacifiCorp and must be 16 taken into account in calculating the costs which any new 17 resource would allow the Company to avoid. 18 Q How do these load and resource conditions 19 relate to the need to price off-peak energy differently 20 from on-peak energy? 21 A During on-peak hours, resources on both 22 sides of the system are balanced with loads to the extent 23 that existing east-to-west transfer rights are adequate to 24 move eastside generation to meet westside loads. When 25 requirements on the east side drop off during off-peak 522 Weaver Di PacifiCorp 1 hours, generation capacity available for transfer to 2 the west side increases. This 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 523 Weaver Di PacifiCorp 1 available off-peak generation exceeds the Company's 2 contractual transfer rights over Idaho Power Company's 3 system as explained by Mr. Morris. As a result, 4 additional off-peak energy on the east side is of limited 5 value to the system. Accepting additional off-peak 6 eastside energy would require that lower-cost coal 7 resources be backed down. Thus the running cost of these 8 resources would be the only costs a new resource would 9 allow the Company to avoid during these hours. 10 Q Does such a limitation exist during peak 11 load hours? 12 A No. Eastside loads are, of course, much 13 higher during on-peak hours. East-to-west transfer 14 capabilities are sufficient to move available on-peak 15 eastside net generation to the westside load centers. It 16 is for this reason that the Company proposes full 17 SAR-based energy prices for Rosebud's on-peak energy 18 deliveries. 19 Q Has Rosebud responded to PacifiCorp's July 20 11, 1994, pricing proposal? 21 A No, Rosebud did not respond to the Company. 22 Rather, on July 14, 1994, it filed an alternative pricing 23 proposal with the Commission. 24 Q Please describe Rosebud's alternative 25 proposal. 524 Weaver Di PacifiCorp 1 A The alternative consists of capacity and 2 energy prices derived from the all-energy SAR 3 non-levelized prices. Beyond this, the alternative is 4 difficult to understand in that there is no description 5 of the derivation or justification of 6 7 / 8 9 / 10 11 / 12 13 14 15 16 17 18 19 20 21 22 23 24 25 525 Weaver Di PacifiCorp 1 the prices, nor is there any contract language 2 establishing how Rosebud intended the prices be applied. 3 Q Is Rosebud's July 14, 1994, alternative a 4 reasonable basis for pricing the project's output? 5 A No. This alternative is based on the 6 inappropriate classification of all fixed costs as 7 capacity costs. As I discussed earlier, a substantial 8 portion of such costs are properly classified as energy 9 costs. This portion should be included in the energy 10 prices, not the capacity prices. 11 Q What is the practical effect of Rosebud's 12 proposed pricing? 13 A These prices result in Rosebud's being able 14 to collect 75% of the SAR-based avoided costs on the basis 15 of capacity to produce rather than on the basis of actual 16 delivery of energy to the Company. This would make it of 17 little importance to Rosebud whether its plant runs 18 reliable or not, since the small energy price would return 19 relatively little margin above costs of the fuel 20 transportation and limestone needed to operate. 21 Q How does Rosebud derive its proposed prices? 22 A It is difficult to say because of the 23 absence of explanation. As indicated, what is being 24 proposed is a two-part price structure. The energy price 25 is the Commission-approved 1994 adjustable portion -- 526 Weaver Di PacifiCorp 1 10.89 mills/kWh -- held constant over the 25 years of 2 prices shown. However, it is possible that Rosebud 3 intends the energy payment to be updated annually 4 5 / 6 7 / 8 9 / 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 527 Weaver Di PacifiCorp 1 using the Commission-approved Adjustable Portion. The 2 capacity price appears to be derived by subtracting this 3 value from each year's Non-Levelized prices from Order 4 No. 25575 and converting to $/kW by applying a 95% 5 availability factor mentioned in the text of the filing, 6 applied as if it were a capacity factor. Note that this 7 application of a capacity factor to the non-adjustable 8 portion generates a premium on the SAR capital cost above 9 that which is included in computing non-levelized rates. 10 This is because these rates are already based on a 75% 11 capacity factor. As with the entire proposal, no 12 justification for this procedure is offered. This 13 capacity price is then discounted by 5% as indicated in 14 the column heading. In fact, the 5% discount was applied 15 twice, producing an actual discount of 9.75%. Note that 16 the double application of the 5% discount cancels out the 17 use of the 95% capacity factor discussed above and 18 produces the same prices as if a 100% capacity factor and 19 a single application of the 5% discount had been used. It 20 is very difficult to negotiate with a party who presents 21 information of this sort without explanation and with no 22 offer to discuss the proposal. 23 Q Have you compared Rosebud's alternative 24 proposed prices with other proposals and projects? 25 A Yes. I have compared them with the 528 Weaver Di PacifiCorp 1 Company's July 11, 1994 proposal, the Company's 2 proposed avoided costs in the current 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 529 Weaver Di PacifiCorp 1 avoided cost case, and with the prices at which the 2 Company will purchase power from the Hermiston project. 3 Hermiston is a 474 MW natural gas-fired cogeneration 4 facility located in eastern Oregon. The prices for the 5 project are set out in the Long-Term Power Sales Agreement 6 Between Hermiston Generating Company, L. P. and 7 PacifiCorp, which was signed on October 7, 1993. 8 Hermiston is scheduled to come on line in July, 1996. 9 These comparisons are presented in Exhibit 114. From this 10 exhibit, it can be seen that Rosebud's proposal is 124% of 11 the Company's proposed prices on a 20-year levelized 12 basis. Comparisons against other measures of currently 13 avoidable costs are also in the 120% range. 14 Q How do these pricing differences translate 15 into total purchased power cost differences which would be 16 imposed by the Rosebud project? 17 A Exhibit 115 presents this comparison. For 18 additional background, the cost of purchases from 19 Hermiston, if it produced the same output as Rosebud is 20 projected to produce, is also included in the comparison. 21 From the exhibit, it can be seen that purchasing the 22 proposed Rosebud project's output at the prices most 23 recently proposed by Rosebud would impose a total cost 24 over a 20-year contract of over $398 million. These costs 25 are $68 million higher than would be incurred purchasing 530 Weaver Di PacifiCorp 1 the project's output at the Company's proposed prices. 2 Even the Company's proposed prices are $16 million 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 531 Weaver Di PacifiCorp 1 higher than purchases at Hermiston prices. Rosebud's 2 proposed prices are $84 million higher than the prices 3 charged for Hermiston's output. 4 Q On page 4 of his testimony, Dr. Slaughter 5 reminds the Commission of its direction that, 6 ... while the design of a rate structure for facilities over 10 MW is a matter for 7 negotiation, a utility's perception of its own load/resource balance and current needs cannot be 8 unilaterally made binding on a QF [.] 9 Has the Company complied with this direction in 10 preparing its July 11, 1994, proposal? 11 A Yes. The Company's proposal is based on the 12 load and resource balance and plant costs upon which the 13 SAR-based rates to which Rosebud seeks grandfathering are 14 based. The Company's proposal is in complete compliance 15 with Commission directives. 16 Q On page 4 of his testimony, Dr. Slaughter 17 goes on to say that since a capacity factor of 75% is used 18 in computing contract prices for smaller QFs, the capacity 19 cost portion of these small QF prices is equal to the 20 inverse of the capacity factor times the capital cost of 21 the SAR. Please respond. 22 A The statement is a non sequitur. The fact 23 that the capacity factor used to compute an all-energy 24 price appears in the denominator of the required 25 calculation tells nothing about the cost of capacity. I have discussed the true economic 532 Weaver Di PacifiCorp 1 cost of capacity as being the lowest cost alternative 2 source of additional capacity. There is simply no 3 relationship between this cost and either the reciprocal 4 of the capacity factor used to compute all energy prices 5 or the capital cost of a plant, such as the coal SAR, 6 which is designed with low running costs in order to be 7 run at a high capacity factor. 8 In addition, the contentions about the appropriate 9 capacity factor to be used in computing all-energy prices 10 is irrelevant in the context of multi-part prices. With 11 separate capacity and energy prices, the capacity factor 12 plays no pricing role at all. The capacity price is paid 13 for actual capacity delivered. It is not rolled into an 14 energy rate based on any assumptions about plant operation 15 and production. 16 Q On page 4 and continuing onto page 5, 17 Dr. Slaughter posits an all-energy priced purchase with 18 the price based on a 75% capacity factor and compares it 19 to a rate-based resource with equal capital and operating 20 costs. He asserts that customers would be indifferent 21 between the two resources with both running at either 75% 22 or 90% capacity factors. Please respond. 23 A This contention is simply wrong. It is 24 based on Dr. Slaughter's erroneous understanding that the 25 Company's revenue requirement is based on an assumed 533 Weaver Di PacifiCorp 1 capacity factor. In fact, the capital cost portion of 2 generation plant revenue 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 534 Weaver Di PacifiCorp 1 requirement recovered through depreciation expense. This 2 procedure allows the company to recover no more than 100% 3 of the capital cost of the plant regardless of the 4 capacity factor at which it is used. It does not allow 5 recovery of an amount computed by dividing such capital 6 cost by any capacity factor. All-energy prices are, of 7 course, based on this division. 8 If both resources do, in fact, operate at the 75% 9 capacity factor used to compute the all-energy purchased 10 resource price, then customers would be indifferent 11 between them. If they both operate at higher capacity 12 factor, however, customers would see lower total costs 13 from the rate-based resource than from the purchased 14 resource. 15 Q Why is this? 16 A This is because, as the rate-based resource 17 produces additional energy, i.e., as its capacity factor 18 increases, the only additional costs to be met by the 19 utility and its customers are the fuel and other variable 20 O&M costs. On the other hand, if the purchased resource 21 produces additional energy, the price the utility and its 22 customers must pay for that energy includes both capital 23 and the variable costs. Here, Dr. Slaughter's reciprocal 24 of the capacity factor is relevant. If 75% is used to 25 compute the all-energy resource purchase price, then the 535 Weaver Di PacifiCorp 1 additional capital cost imposed by the additional energy 2 would be based on 133% of the capital 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 536 Weaver Di PacifiCorp 1 cost of the pricing resource -- the SAR in this case. 2 This additional cost to the utility is, of course, a 3 windfall gain to the QF because it experiences no increase 4 in its capital cost in order to receive the additional 5 revenue. 6 Q On replacement page 6 of his testimony, 7 Dr. Slaughter complains about the Company's proposed use 8 of Rosebud's 88% capacity factor for converting the energy 9 portion of capital cost to a mills/kWh basis. Please 10 respond. 11 A Dr. Slaughter apparently would prefer "the 12 utility's CF [capacity factor]." PacifiCorp's actual 13 capacity factors for its large eastside coal units is in 14 the 90 to 95% range, not the 75% used to compute SAR-based 15 energy-only rates for small QFs. 16 Q Does any of Dr. Slaughter's discussion of 17 capacity factors carry into Rosebud's July 14, 1994, 18 alternative pricing proposal? 19 A No. That proposal, as I have indicated 20 above, is for a two-part capacity and energy pricing 21 structure. Appropriately, capacity factor has no role in 22 those prices. 23 Q On page 8 of his testimony, Dr. Slaughter 24 lists the elements in the SAR all-energy pricing method 25 for small QFs which are included in the non-adjustable 537 Weaver Di PacifiCorp 1 portion of those rates. He then states: "All of these 2 components are properly considered capacity costs." Is 3 this a reasonable classification of these cost elements? 4 5 / 6 7 / 8 9 / 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 538 Weaver Di PacifiCorp 1 A No. Dr. Slaughter is fundamentally 2 confusing capital costs with capacity costs when, in fact, 3 capital costs must be classified between capacity and 4 energy components. I have addressed the issue of 5 classification of the capital cost of coal-SAR-type 6 generation units. Only the portion of such costs 7 corresponding to the lowest priced alternative capacity 8 resource are properly classified as capacity-related 9 costs. The balance are properly classified as 10 energy-related. As indicated, the cost of a SCCT is the 11 appropriate basis for costing capacity. It is not 12 surprising that this issue has not been addressed in 13 establishing SAR-based rates for small QFs. It is 14 irrelevant to the calculation of such all-energy rates. 15 When the Commission allows negotiation of separate 16 capacity and energy rates for larger QFs like Rosebud, 17 this issue arises for the first time. No guidance on the 18 valuation of capacity can be derived from the thinking 19 behind the proper calculation of small QF all-energy 20 rates. I would note that Dr. Slaughter continues with his 21 confusion between capacity and capital costs elsewhere in 22 his testimony such as his discussion on page 11. His 23 arguments there are equally invalid for the same reasons 24 as discussed here. 25 Q Beginning on page 10, Dr. Slaughter suggests 539 Weaver Di PacifiCorp 1 a power purchase arrangement between Rosebud and 2 PacifiCorp based on the Commission's Order No. 25706 in 3 Rosebud's Idaho Power complaint case. Do you agree with 4 this suggestion? 5 6 / 7 8 / 9 10 / 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 540 Weaver Di PacifiCorp 1 A No. This is the first time such a 2 suggestion from anyone connected with Rosebud appears. It 3 is inconsistent, for example, with both the October 1993 4 and the July 1994 Rosebud proposals. PacifiCorp has not 5 evaluated an Idaho Power-like pricing option. This 6 suggestion is too late and too ill-defined to be given 7 serious attention at this time. 8 Q On page 11 of his testimony, Dr. Slaughter 9 states that peaking facilities are "of little use to 10 ratepayers." Is this a reasonable characterization? 11 A No. Dr. Slaughter is saying that there is 12 little value to customers in the utility being able to 13 deliver power at precisely the times when the customers 14 are expressing the highest desire or need for power. 15 Indeed, peaking resources are "of use" to ratepayers, 16 because without them, either power could not be delivered 17 when it is wanted most or high capital cost resources 18 would have to be maintained on the system and paid for by 19 customers to meet those relatively few hours of the year 20 when the power is needed. 21 Q On page 1 of his testimony, Mr. Roberts 22 refers to what he calls record load growth in the 23 Company's Idaho service territory. What is your response? 24 A The Company is not experiencing record load 25 growth in its Idaho service territory. In fact, the 541 Weaver Di PacifiCorp 1 Company's Idaho loads have been relatively flat over the 2 last five years. Growth 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 542 Weaver Di PacifiCorp 1 is nowhere near record levels in Utah Power's Idaho 2 service territory. 3 The Company submitted an interrogatory regarding 4 the basis of Mr. Robert's claim. The response was a 5 voluminous report prepared by Idaho Power Company on 6 economic and demographic trends in its service territory. 7 There was nothing in the response referring to load growth 8 -- record or otherwise -- in Utah Power's Idaho service 9 territory. The part of the state served by Utah Power is 10 not comparable Idaho Power's service territory, which 11 includes the high growth areas around Boise. 12 Q On pages 8 and 9 of his testimony, 13 Mr. Roberts claims that, "...PacifiCorp has refused to 14 make an offer consistent with existing rates and 15 methodology...." Is that a legitimate characterization? 16 A Not at all. I have described the Company's 17 pricing proposal in extensive detail. It consists of two 18 straightforward adjustments to the published rates using 19 the approved methodology. The adjustments are consistent 20 with Commission directives and are appropriate to produce 21 rates which reflect the existing coal-SAR-based costs 22 which the project would actually allow the Company to 23 avoid. 24 Q On pages 14 and 15 of his testimony, 25 Mr. Roberts discusses dispatchable SAR-method pricing. 543 Weaver Di PacifiCorp 1 He asserts that if the Commission adopts dispatchable 2 SAR-based pricing, "system 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 544 Weaver Di PacifiCorp 1 losses" included in PacifiCorp's July 11, 1994, proposal 2 become irrelevant. Please respond to those statements. 3 A I believe Mr. Roberts is referring to the 4 transmission limitation between the east and west sides of 5 the Company's system, as discussed by Mr. Morris, and not 6 to system losses. This transmission limitation, not 7 system losses, is the basis of computing the 8 dispatchability adjustment to the existing approved 9 avoided costs. The role of system losses in computing the 10 Company's proposal is exactly the same as it is in 11 computing the existing SAR-based avoided costs approved by 12 the Commission. If losses were removed, avoided costs 13 would decline by about 1.8 percent. The Company has not 14 proposed such removal. 15 Q Mr. Roberts asserts that, "... ratepayers 16 will receive substantial benefits" from the low cost 17 off-peak energy in the Company's proposal. Is this 18 correct? 19 A No. I have demonstrated that the Company's 20 proposal is fair to both customers and the QF developer. 21 It is fair to customers in that, to the extent that the 22 current SAR-based prices truly reflect avoided costs, it 23 leaves customers indifferent between power from Rosebud 24 and power from any alternative resource. There is neither 25 windfall benefit nor harm to customers. The Company's 545 Weaver Di PacifiCorp 1 proposal is fair to the developer because it represents 2 the full costs that the project would allow the Company to 3 avoid by accepting project 4 5 / 6 7 / 8 9 / 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 546 Weaver Di PacifiCorp 1 output. The Company's proposal also is more than 2 sufficient to encourage the development of cost effective 3 new generation. It is, in fact, $16 million higher than 4 the Company would be paying for an equivalent amount of 5 power from the Hermiston project. 6 Q Does this complete your direct testimony? 7 A Yes. 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 547 Weaver Di PacifiCorp 1 (The following proceedings were had in 2 open hearing.) 3 MR. ERIKSSON: And I have some surrebuttal 4 that I'd like to have Dr. Weaver address. 5 COMMISSIONER MILLER: All right, we'll give 6 it a try. 7 8 DIRECT EXAMINATION 9 10 BY MR. ERIKSSON: (Continued) 11 Q Dr. Weaver, have you read the rebuttal 12 testimony of Dr. Slaughter? 13 A Yes, I have. 14 Q Will you please turn to Page 10 of that 15 testimony? 16 A Yes, I have it. 17 Q On that page, Dr. Slaughter agrees with you 18 that since Rosebud would be a marginal resource, energy 19 provided off peak has value only to the extent that fuel 20 is saved at other PacifiCorp Utah plants as he identifies 21 it; however, he suggests that your perspective, as he 22 calls it, should not be adopted by the Commission. How do 23 you respond to that? 24 A I'd like to first point out that my 25 perspective from within the Company is the perspective of 548 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 the interest of our Company's customers. What I've done 2 in designing these prices is to design a set of prices to 3 pay Rosebud a coal SAR-based cost which its output would 4 allow us to avoid. This is in pursuit of the PURPA 5 ratepayer indifference standard. Clearly, that's the 6 appropriate perspective for consideration of all QF 7 pricing issues. 8 Now, as to the three reasons that 9 Dr. Slaughter offers why the Commission should not adopt 10 the consumer's interest perspective that I've adopted, I'd 11 like to deal with those. The first two perspectives -- I 12 mean reasons not to adopt that perspective seem somewhat 13 to run together. They seem to be a combined claim that 14 the transmission limitation on which this particular piece 15 of the analysis depends results from a combination of poor 16 planning and an excessive orientation on the part of the 17 Company to base load resources. 18 First of all, that's not true. The 19 existence of base load resources to the extent they exist 20 on the system in the way we're allowed to use them allows 21 us to meet a very substantial portion of our customers' 22 total energy needs from high efficiency coal burning 23 resources on the east side of our system. That's a 24 benefit to our customers and paying Rosebud prices higher 25 than those that I proposed would take away a portion of 549 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 that benefit by paying Rosebud higher prices than what the 2 customers would otherwise have to pay in costs; however, 3 even if it were true that the limitation that results in 4 this condition limiting the value of Rosebud's output off 5 peak did come about as a result of poor planning and come 6 about as a result of excessive orientation to base load 7 resources, under PURPA that's irrelevant. Avoided cost 8 pricing is to be based on increments to the existing 9 system as built and operated, and, clearly, my analysis 10 starts with the existing system as built and as operated 11 and is consistent with that aspect of PURPA. 12 Now, the third item, reason why 13 Dr. Slaughter suggests not adopting my perspective is that 14 load growth on the east side of the Company's system, over 15 a relatively short time he implies, will eliminate the 16 effect of the transmission limitation, and that's not a 17 trivial point to raise; however, in order to respond to 18 it, I'd like to describe the analysis that supports my 19 Exhibit 113, the load growth elements in my Exhibit 113. 20 Those load growths, recall, the load numbers 21 appearing in 113 are off-peak loads on the system. They 22 don't reflect on-peak loads. Now, those loads themselves 23 are not based on RAMPP-3 numbers which Dr. Slaughter 24 refers to in his rebuttal testimony. Instead, they're 25 based on the ongoing analysis generating the updated load 550 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 growths which will appear in RAMPP-4. They are in fact 2 updated numbers. 3 Second, and this is important, the numbers 4 are off-peak loads. Our off-peak loads consist of a 5 higher proportion than do our on-peak loads of high load 6 factor, industrial, manufacturing and mining loads. Those 7 customer segments on our system are growing much less 8 rapidly than are the low load factor on-peak loads in the 9 residential and commercial segment of our business. 10 Therefore, it's perfectly reasonable to expect that the 11 off-peak load growth rates are going to be slower than 12 on-peak load growth rates. 13 Finally, my Exhibit 113 load growths account 14 for some specific load losses which are not accounted for 15 in RAMPP-3, including loss of Wyoming Oil load, which 16 we've got 90 megawatts of that which we are in the process 17 of losing right now. That is a 100 percent load factor 18 load. 19 Also, it includes the loss of the 20 Montana-Dakota Utility sale, a 50 megawatt sale, which 21 also has a high load factor. Both of those elements were 22 not included in RAMPP-3. They are included in my 23 Exhibit 113, but, of course, I've been a forecaster a long 24 time and the one thing you know about forecasts is they're 25 going to be wrong. It is entirely possible that the load 551 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 growths appearing in my Exhibit 113 will turn out to be 2 too low. It's also possible it will turn out to be too 3 high, but I would like to point out that in order for east 4 side off-peak load growth to eliminate the effect of the 5 transmission limitation that Mr. Morris describes, we'd 6 need to have an increase of 1,300 megawatts in east side 7 off-peak load. That's the magnitude of the surplus. In 8 order to increase load by 1,300 megawatts between '95 and 9 the year 2000, which is the period of that analysis, I 10 would have to have an annual average growth rate of eight 11 percent. 12 Q Is that for off-peak load? 13 A That is the off-peak load, exactly. 14 Dr. Slaughter correctly points out that RAMPP-3 calls for 15 an increase of load on the east side of the system on peak 16 of 500 megawatts in that interval. 500 megawatts is just 17 something over a third of the 1,300 megawatts we'd need 18 and recall again that that 500 megawatts is on-peak load, 19 not off-peak load. 20 Finally, RAMPP-3 also talks about something 21 like a two percent rate of growth. If we were to apply 22 that two percent off peak, even though I'd claim that 23 that's not the reasonable thing to do, if we were to do 24 that, it would take 20 years for load growth to grow to 25 the extent that that 1,300 additional megawatts would 552 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 occur. If the three percent load growth, again applied 2 off peak, not on, that's established in the last, the 170 3 case were to be applied, it would take something 4 approaching 15 years to eliminate or to provide the 1,300 5 megawatts necessary to eliminate the effect of the 6 transmission limitation. 7 One other point, all of this analysis 8 assumes that there are no new resources added on the east 9 side. I'd like to point out, clearly, there's one 10 prospect for additional resource being added, that being 11 the Rosebud project that we're discussing here, and that's 12 only 40 megawatts of what we're now looking at under 13 discussion of something nearly 700 megawatts of QF power 14 on the east side, most of that right now in the State of 15 Utah, three projects in the State of Utah and one that has 16 just approached us that is talking about locating itself 17 either in the State of Wyoming or the State of Montana. 18 Of course, any additional resource occurring on the east 19 side would further extend the period during which the 20 transmission limitation is effective. 21 The conclusion of all that, of course, is 22 that the transmission limitation is in fact a long-term 23 phenomenon and one which load growth can't be expected to 24 eliminate anything like the near term. 25 There's one other consideration. To the 553 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 extent that Rosebud is concerned about eventually the 2 transmission limitation becoming ineffective, we'd 3 consider the possibility of including a reopener clause in 4 any contract that we would ultimately negotiate. We would 5 want, of course, such a reopener to be negotiated in the 6 context of an overall contract which may have other 7 reopeners to serve, protect the interests of PacifiCorp 8 and its customers as well as possibly, other ones that 9 might protect the interests of Rosebud. 10 All of that is to suggest that with regard 11 to this point, I have adopted the correct customer 12 interest perspective and none of the reasons that 13 Dr. Slaughter deduces that the Commission ought not to 14 adopt that customer interest perspective are persuasive 15 and, therefore, the analysis stands and should be accepted 16 by the Commission. 17 Q On Page 10, he makes a point, makes a claim 18 about PacifiCorp not having previously raised this issue 19 in avoided cost cases. Is this issue raised for the first 20 time that you're aware of with Rosebud? 21 A To my knowledge, it is. Rosebud is the 22 first QF larger than 10 megawatts that we've had to deal 23 with in the State of Idaho and it's the first time I 24 believe that this issue has been raised. 25 Q If you could turn to Page 7 of 554 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 Dr. Slaughter's rebuttal, the last line on that page and 2 carrying over on to Page 8, Dr. Slaughter says, "What 3 Mr. Weaver has done is to substitute an entirely different 4 surrogate plant under the guise of a scheduling 5 adjustment." Is that what you've done? 6 A No, that is not what I have done. As I've 7 explained extensively in my testimony, what I've done is 8 constructed a price scheme for a large non-dispatchable QF 9 on the east side of the system which would pay the QF 10 exactly the costs which its production would allow the 11 Company to avoid. What Dr. Slaughter is referring to here 12 is my use of the simple cycle CT. What I've done with 13 that is standard practice. It's exactly the same practice 14 as we use in all of the other states where we establish 15 avoided costs to classify the capital cost of the SAR unit 16 between a capacity component and an energy component. 17 At that stage of the analysis not a single 18 dollar of SAR costs are eliminated. All I've done with 19 the simple cycle CT is to properly classify the total 20 capital of building one of those kinds of units between 21 the cost of providing capacity to the system and the cost 22 of providing energy to the system. 23 Q On the same page, this is Lines 24 to 25, he 24 states: "The cost of QF power to the utility does not 25 rise because a developer produces above the 75 percent 555 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 level"; is that correct? 2 A What page are we on? 3 Q Page 5. 4 A I'm sorry. 5 Q It's at the very bottom of the page. 6 A Yes, he does say that and, no, that's not 7 correct. What he's comparing here is the cost of power 8 purchased from the QF to the cost of the same amount of 9 power produced by a company-owned SAR, and I've gone 10 through this in my direct testimony, also. If the Company 11 owns the SAR, it recovers investment in the SAR through 12 the depreciation expense included in established revenue 13 requirement. If the Company is buying power from a QF and 14 the QF's -- then its price goes up, the total spending I 15 mean on the product goes up when more quantity is 16 purchased; however, the amount by which the spending to 17 the QF goes up includes additional recovery of capital for 18 each additional megawatt-hour produced and sold. The cost 19 of a company-owned rate based resource when production 20 goes up above 75 percent is just the additional running 21 cost. It does not increase capital at all, capital costs 22 at all; therefore, the cost of the increased production 23 from the QF costs ratepayers more than does the same 24 amount of increased production from a company-owned rate 25 based resource. 556 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 Q On Page 5, Lines 6 through 8, he states: 2 "Under the PacifiCorp proposal, for peak energy only, 3 Rosebud receives the same payment as the SAR only if it 4 produces 88 percent capacity, relative to the SAR's 5 75 percent"; is that correct? 6 A Yes, that is correct, and I just explained 7 why and it's entirely appropriate that that happen. It's 8 appropriate because that would represent exactly the 9 capital cost and running cost that the QF's production 10 allows the Company to avoid. If it weren't the case, then 11 the QF would be receiving more than the total capital cost 12 that it allows the Company to avoid. In fact, the 75 13 percent that's used, 75 percent capacity factor that's 14 used, to compute the all energy rate for small QFs, those 15 less than 10 megawatts, is appropriate in that it would 16 allow the QFs as a group to exactly be compensated for the 17 costs they avoid if that group would average about 75 18 percent capacity factor on average. That way the group of 19 QFs would be compensated exactly to the amount that they 20 allow the Company to avoid in costs and that, again, is 21 the ratepayer interest perspective that all of this 22 analysis is based upon. 23 However, with a large single QF like 24 Rosebud, in order to convert the energy portion of the 25 capital spending required to build the SAR into a per 557 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 kilowatt-hour basis so they can be collected with energy 2 production, it's necessary that the QF's capacity factor 3 be used to make that conversion. Again, if that isn't the 4 case, then the QF will be overcompensated. It will get 5 more in return for its production than it allows the 6 Company to avoid in capital costs. 7 A lower capacity factor, a 75 percent 8 capacity factor, used to convert capital costs to a per 9 kilowatt-hour basis for a QF that runs a higher capacity 10 factor than that would overcompensate the QF, pay it more 11 than it allows the Company to avoid. 12 Q I'm sorry for skipping around a bit here, 13 but if we go back down towards the bottom of that page, if 14 you would read Lines 21 through 24 and tell me if you 15 agree with that. 16 A Lines 21 through 24 says, "If a developer 17 brings on line a plant with higher than 75 percent 18 capacity factor the utility avoids additional costs 19 associated with construction of more 75 percent capacity 20 factor plant." I don't believe that that's the case. 21 There are other resources that are available to acquire 22 just energy. Other resources on the system could be run 23 harder; therefore, their energy production could go up or 24 for just producing energy, not capacity, there are 25 resources in the market. Simply going into the market and 558 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 buying energy at much less cost than building a whole new 2 plant is available in the market. Those are the real 3 costs that this additional energy produced by the QF 4 operating at higher than 75 percent would allow us to 5 avoid. 6 I'd like to point out one other thing. I've 7 suggested in this computation that for the Rosebud QF 8 which has a high capacity factor, our calculations would 9 impose their capacity factor in converting capital to 10 energy. We would adopt exactly the same practice if we 11 were dealing with a large QF with a low capacity factor. 12 In that case, the low capacity factor would be appropriate 13 to use in converting capital to energy basis. 14 Q Could you turn to Page 2 of the rebuttal 15 testimony, and at the bottom of that, there's a sentence 16 that carries on to Page 3 in which Dr. Slaughter asserts 17 that you pointedly reject the capacity cost calculation 18 inherent in Commission methodology. Do you see that as a 19 correct -- or how do you respond to that? 20 A Well, I think that's simply an inappropriate 21 characterization of what I've done. There isn't really in 22 the Commission's spreadsheet model a method for dealing 23 with capacity, per se. What the spreadsheet model deals 24 with is spreading the capital cost of the SAR into an all 25 energy rate. Order 22865, for example, discusses using 559 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 the capacity factor or, in fact, the equivalent 2 availability factor to convert capital cost to an energy 3 basis, not to convert capacity cost to an energy basis. 4 Looking at Commission Order 22636, they make 5 it clear that they expect a capacity portion of a 6 multi-part pricing arrangement like the one we're 7 proposing for Rosebud to be substantially less than the 8 total capital cost that gets spread to an all energy rate 9 in the standard published avoided costs for small QFs. 10 I'd like to point out that this confusion 11 between capital and energy, the inappropriate 12 classification of all capital costs as being capacity 13 costs is an error that occurs in Dr. Slaughter's testimony 14 in a number of places, but its corresponding error on the 15 energy side is also there. On Page 6 of his testimony, 16 Lines 20 to 26, he characterizes the adjustable portion of 17 the Commission's all energy rate as being the energy 18 portion. In fact, the adjustable portion is just part of 19 the energy payment. The capitalized energy portion is the 20 other part. My analysis properly classifies total capital 21 between capacity and energy, prices them both as separate 22 products, and that's the appropriate way to structure such 23 a contract as this. 24 Q On Page 3, also, he states that, this 25 appears at Line 6, that your pricing calculation penalizes 560 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 a QF for efficiency. Do you see that as a correct 2 statement? 3 A No. My pricing structure is designed to 4 exactly pay the QF, a large non-dispatchable QF, exactly 5 the cost that it allows the Company to avoid; thereby, 6 again, pursuing the interests of the ratepayers, 7 protecting the interests of the ratepayers. The 8 efficiency of the QF, whether it's high or low, is not a 9 concern or a target of the pricing mechanism. It's got 10 nothing to do with it. If the QF can operate under these 11 prices efficiently or inefficiently, that's up to them. 12 It's got nothing to do with what we're engaged in here. 13 Q On Page 4, Lines 20 to 24, he has a question 14 and answer about the explanation of how your Column 6 of 15 your price calculation, that is, Exhibit 112, represents 16 payment for capacity. Is there an inaccuracy in this 17 question and answer there? 18 A The inaccuracy is in the formulation of the 19 question. It asks how my Column 6 in my Exhibit 112 20 proposes to pay for capacity. It simply doesn't. It 21 proposes to pay for energy, not capacity. Again, this 22 simply is a continuation of another instance of the 23 confusion between the terms capital and capacity. What 24 Column 6 is doing is structuring the price for the energy 25 component of the capital involved in building the SAR. 561 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 Q And in that answer, he says that the effect 2 is to reduce avoided cost? 3 A He says that. I'd simply replace that word 4 "reduce" with "reflect." The effect is to reflect 5 avoided costs, properly incorporate them in the pricing 6 structure. 7 Q And on Page 6, Lines 15 to 16, he states 8 that you still propose a 75 percent capacity factor for 9 rates covering this period of time. Does he properly 10 characterize the status of the Company's interim rate 11 proposal? 12 A No. The interim rates, our interim rate 13 proposal was denied by the Commission. They granted an 14 alternative form of interim relief. Our interim proposal 15 has no effect at all. 16 Q On Page 10 of his rebuttal, he asserts that 17 the effect of the Company's contract with BPA, that is, 18 the BPA exchange agreement, is to make the coal plants 19 dispatchable. How do you respond to that? 20 A Well, the BPA contract neither makes the 21 coal plants dispatchable, nor does it make them 22 indispatchable. The coal plants are dispatchable because 23 of the fact that we own the things and we can run them 24 based on our own determination of the economic efficiency 25 of each individual unit. They're part of the system, 562 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 they're dispatched. 2 The BPA contract does support our ability to 3 dispatch them to a higher extent than we would otherwise, 4 which is a very good thing. If we couldn't do that, then 5 we'd have to have higher energy costs. We might also have 6 to have more costly capacity resources than the BPA 7 allows. 8 Further, this seems to indicate 9 Dr. Slaughter's recognition of the fact that coal plants 10 are dispatchable. He says that the BPA contract allows us 11 to run the coal plants harder than we otherwise would. 12 That's the very essence of dispatchability. We get to 13 decide based on all the cost elements on the whole system 14 how hard to run those plants. That's the very essence of 15 dispatchability, that coal plants in fact are 16 dispatchable. 17 Q Further down on the same page, Lines 13 18 through 16, essentially, he says that you argue that any 19 new QF resource must be designed to provide power only 20 during peak periods. Is that what you argue? 21 A My pricing structure, as I said a number of 22 times, is designed simply to compensate a large 23 non-dispatchable resource for exactly the cost it allows 24 the Company to avoid. It doesn't say a thing about how a 25 QF should design its power, design its -- yeah, how its 563 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 resource must be designed to provide power. It's not the 2 concern of the Company given this pricing structure how 3 Rosebud or any other QF designs and operates its 4 non-dispatchable resource. We would simply pay them the 5 costs that they allow us to avoid, which is the 6 appropriate thing for us to do. 7 MR. ERIKSSON: I have nothing further and 8 he's available for cross. 9 COMMISSIONER MILLER: All right, he's 10 available for cross. Mr. Orndorff. 11 12 CROSS-EXAMINATION 13 14 BY MR. ORNDORFF: 15 Q Mr. Weaver, could you tell me how the rates 16 in Exhibit 63 were calculated? 17 A Exhibit 63, I don't have a copy of that with 18 me. Exhibit 63 is a letter dated January 13th, 1993, to 19 Mr. Orndorff from Mr. Fell. It has an attachment called 20 "Avoided Cost Prices for Purchase Power," and it shows 21 three -- five, I mean, years of firm energy prices, 22 winter, summer, average, and what those appear to me to be 23 is the then current, probably, energy component avoided 24 costs from, it looks like, Oregon from its structure. 25 The way they're computed is by using our 564 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 production dispatch model. The production dispatch model 2 is run assuming a given set of resources and then it's run 3 again assuming that there's a 50 megawatt zero running 4 cost resource, which, of course, any dispatched model 5 would run all the time. The total power cost difference 6 between the with and without 50 free megawatt resource run 7 is then converted into these avoided energy cost numbers. 8 They then get seasonalized simply by proper accumulation 9 of months. It's a monthly model. The winter months are 10 used to produce the winter column, the summer months to 11 produce the summer column. 12 Q As far as you know, does that exhibit, do 13 those rates have any similarity to the SAR method used in 14 Idaho for computing avoided cost? 15 A I believe not. 16 Q Can you tell me how the rates in Exhibit 104 17 were calculated? 18 A Maybe I can do that. Yes, this is the 19 April 16th informational pricing letter which the Company 20 prepared for Mr. Orndorff coming out of one of the 21 prehearing conferences, I don't remember which one, 22 characterized as being informational and for the purpose 23 of allowing Rosebud to investigate the feasibility of its 24 project. 25 These were produced by looking at then 565 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 current market alternatives that the Company faced. In 2 specific, it included the Hermiston project which was then 3 nearing completion; a very similar project to be located 4 in the Cowlitz area in the State of Washington which had 5 similar pricing provisions, it hasn't come to fruition; 6 the James River 50 megawatt cogeneration facility; and the 7 new Sunnyside, additional Sunnyside, Utah QF capacity 8 contract, all of those taken as an investigation of what 9 the market was like at that time and those were the bases 10 for these numbers here. 11 Q Have you ever reviewed Commission 12 Order 24383? 13 A I expect that I know that you're generally 14 going to ask the question what have these prices got to do 15 with -- I should just answer the question. In general, I 16 think I probably know what that's about. 17 Q You have reviewed the Order? 18 A I don't know it by name. 19 Q I believe it's attached to Exhibit 65 and 20 the relevant page might be the last page in Exhibit 65. 21 A I don't have Exhibit 65 -- I do have 22 Exhibit 65. The last page of text I take it you mean? 23 Q Of the Order. I believe it's entitled, 24 "Average Non-Levelized Avoided Cost Rates" for 25 PacifiCorp. 566 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 A Yes, I see that. 2 Q Have you reviewed those rates? 3 A I'm generally familiar with these rates, 4 yes. 5 Q And when providing the rates for Exhibit 63 6 and Exhibit 104, it's your testimony you really didn't 7 review these rates at all? 8 A It's my testimony that those rates were 9 produced as I said that they were produced. 10 Q Now, on Page 2, Lines 5 through 11 -- 11 MR. ERIKSSON: What are you referring to? 12 MR. ORNDORFF: I'm referring to his 13 testimony. 14 MR. ERIKSSON: Thank you. 15 Q BY MR. ORNDORFF: On Page 2, Lines 5 through 16 11, you indicate that you have used avoided costs in 17 effect prior to January 14th, 1994. Do you see that? 18 A Yes. 19 Q Didn't you change the SAR methodology to 20 adjust the rates as explained in Exhibit 112? 21 A What I did was started with the approved 22 coal SAR-based rates and computed two adjustments that 23 allow us to reflect the coal SAR-based rates that the 24 Rosebud project would allow us to avoid, recognizing it as 25 a non-dispatchable resource and basing that on the line 567 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 item adjustment that the Commission has allowed dealing 2 with schedulability. 3 Q Did you change the assumptions in the SAR 4 methodology? 5 A I did not change any of the assumptions in 6 the SAR methodology. 7 Q I see. Would you read with me now on 8 Exhibit 112, second paragraph, third sentence, first page? 9 A I've got the exhibit. Tell me the lines you 10 want again. 11 Q Second paragraph, third sentence. It starts 12 off, "The non-approved-SAR-method assumptions...." 13 A Yes. 14 Q Would you read that sentence to us? 15 A "The non-approved-SAR-method assumptions are 16 the construction cost of the simple cycle combustion 17 turbine peaking resource, the escalation rate applied to 18 the SCCT construction cost, and the Montpelier project 19 capacity factor." 20 Q I'd like to ask you again, did you change 21 the assumptions? 22 A And I'll give you the same answer. As you 23 can see by looking at the Page 3 of 3 of that exhibit, 24 none of the SAR adjustments have been changed. What has 25 been done is I've used the simple cycle combustion turbine 568 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 construction cost to classify the capital component of the 2 SAR project into a capacity component and an energy 3 component. That does not entail changing any SAR 4 assumptions. I used the 88 percent of Rosebud's -- the 5 88 percent capacity factor set by Rosebud in its then 6 current, it's called Exhibit A, I forget what it was 7 attached to, Appendix A, to convert the capital cost, the 8 energy component of the capital cost to a per 9 kilowatt-hour basis. 10 Q Have you reviewed Commission Order 25454 and 11 that's in the Idaho Power-Rosebud case? 12 A I haven't paid particular attention to that 13 Order. As you say, it's the Idaho Power case. 14 Q Mr. Weaver, who determines avoided costs? 15 A In the State of Idaho, the Idaho Public 16 Utilities Commission determines avoided costs. 17 Q Have you filed this methodology that you 18 propose with the Idaho Commission prior to Rosebud's 19 complaint? 20 A No, we've never been involved in pricing 21 output for a project above 10 megawatts in the State of 22 Idaho before; therefore, we've never addressed this 23 problem and we've never filed anything to do deal with 24 this problem before. 25 Q Mr. Weaver, does Utah Power and PacifiCorp 569 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 have the ability to sell energy into the Southwest through 2 Utah? 3 A Yes, we do. 4 Q Do you know what the size of those 5 interconnections are? 6 A I can't testify to the transmission 7 capacities on our system. 8 Q Does Utah Power have any transmission 9 enhancements scheduled for construction in the next five 10 years? 11 MR. ERIKSSON: I think these questions will 12 go to Mr. Morris more appropriately. He's testified as to 13 the transmission constraints. 14 MR. ORNDORFF: Okay. 15 Q BY MR. ORNDORFF: Now, Mr. Weaver, you, I 16 gathered, sponsored an economic forecast as part of your 17 rate methodology; is that correct? I'm looking at 18 Exhibit 113. 19 A Oh, well, one component of Exhibit 113 is 20 expected off-peak native growth for the period 1995 to 21 2000. 22 Q Have you had a chance to review Commission 23 Order 23358? 24 A I frankly don't know whether I have or not. 25 Q Are you aware -- 570 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 MR. ERIKSSON: Excuse me, could he have a 2 specific question with respect to the Order? I mean, is 3 it directed at something in the Order? 4 COMMISSIONER MILLER: To the extent that's 5 an objection, we'll overrule it and allow Mr. Orndorff to 6 proceed. 7 MR. ORNDORFF: Thank you, Mr. Chairman. 8 Q BY MR. ORNDORFF: Are you aware that as part 9 of the SAR methodology, the Commission in that Order 10 adopted a three percent growth projection as an 11 assumption? 12 A Yes, I am and, in fact, I've talked about 13 that already this afternoon. That three percent is, of 14 course, consistent with the SAR methodology for small QFs 15 and on-peak oriented load growth. These off-peak numbers 16 that we're showing here for reasons I've already talked 17 about reflect current off-peak expectations, and as I also 18 said, if we were to apply that three percent growth to the 19 1995 native load numbers that are relevant to determining 20 how effective the transmission limitation is, even at 21 that, the transmission limitation would be maintained for 22 something approaching 15 years, but I've also said that 23 the three percent is not relevant to these kind of 24 numbers. 25 Q I only have one more area I want to pursue 571 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 with you, Mr. Weaver. You mentioned a reopener in your 2 supplemental or surrebuttal. What is a reopener? I 3 believe you've never brought that up with Rosebud; is that 4 true? 5 A Well, it is true that we haven't. The point 6 of my mentioning it at this point is simply that it would 7 be a reasonable negotiation issue if in fact we would ever 8 be engaged in negotiation. You seem to be concerned with 9 the prospect of the transmission limitation being 10 eliminated. One way to accommodate your concern would be 11 to open the possibility of investigating on an annual 12 basis whether that's happened. 13 I've got nothing to say right now about how 14 we would structure such a reopener or how we would verify 15 whether the limitation had been eliminated, but given all 16 of that, it would be possible to negotiate an element in 17 the contract to reopen the off-peak energy price issue 18 when and if through negotiated processes and verification 19 techniques the limitation were eliminated. It's only an 20 attempt to recognize that there are ways to deal with such 21 issues. 22 Q I'm not really familiar, Mr. Weaver, with 23 the Firth contract. I presume the Firth contract had a 24 similar provision and a reopener? 25 A No idea. I didn't do the Firth contract. 572 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 Q Does the Sunnyside contract have a reopener 2 in it? 3 A I don't believe that it does. 4 Q Do you have any contract that has a reopener 5 in it as you describe? 6 A To my knowledge, not, although I wouldn't 7 say for sure that we don't; however, we haven't raised -- 8 this particular concern hasn't been raised in negotiations 9 up to date and as I said, I only put it there as an 10 indication that issues such as the magnitude and duration 11 of the transmission limitation could be subject to 12 negotiation. It was something that we would be willing to 13 talk about for the benefit of Rosebud. 14 MR. ORNDORFF: Mr. Chairman, I have nothing 15 more for Mr. Weaver. 16 COMMISSIONER MILLER: Thank you, 17 Mr. Orndorff. 18 Commissioner Nelson. 19 COMMISSIONER NELSON: Thank you. 20 21 EXAMINATION 22 23 BY COMMISSIONER NELSON: 24 Q I had one question come to my mind. Did I 25 understand you to say that you're pricing Rosebud as 573 CSB REPORTING WEAVER (Com) Wilder, Idaho 83676 PacifiCorp 1 though it were non-dispatchable? 2 A Yes, absolutely. 3 Q Wouldn't it be just synonymous to say that a 4 peaking unit would have to be dispatchable? 5 A I'm sorry, I don't understand the question. 6 Certainly, if we owned a peaking unit, it would be 7 dispatchable. 8 Q Well, my concern is that you are pricing the 9 capital portion of this based on that SCCT which would be 10 a peaking unit, which to me, just by its nature, is a 11 dispatchable unit and yet, you stated that Rosebud is 12 non-dispatchable. 13 A What I've done is tried to structure prices, 14 and I've tried to make this clear, in such a way that 15 Rosebud would be paid for the capacity and energy costs 16 that it actually allows us to avoid. Capacity is a 17 product which can be bought on the market either in the 18 form of buying company-owned peaking-type units like a 19 simple cycle CT or, alternatively, simply buying what's 20 called naked capacity from other utilities. 21 We have three such contracts on our system 22 now that I can think of, one being the BPA contract that 23 we've talked about in testimony here; another one being a 24 winter capacity purchase from Southern Cal Edison; and a 25 third one being Water Power's summer capacity purchase. 574 CSB REPORTING WEAVER (Com) Wilder, Idaho 83676 PacifiCorp 1 Those are paid for based on the ability to deliver power 2 when the Company needs it on peak. 3 The capacity price in my calculation to 4 Rosebud is exactly analogous to that. Rosebud would be 5 paid the capacity price on a megawatt delivered basis, not 6 megawatt-hours, not energy. It's the ability to deliver 7 power on peak and that price is based on a standard in the 8 industry of the cost of such peaking resources. That's 9 what they would get paid for capital, and the total 10 contract of which this pricing scheme is a part sets out 11 the mechanism under which the amount of capacity they 12 deliver each month is determined. All of that is quite 13 standard contract language. 14 Then the other portion of the capital cost 15 of the simple cycle CT is a large chunk of capital that is 16 built that so these plants can produce energy 17 efficiently. It's not to do with providing capacity to 18 meet peak demand. It's concerned with providing energy on 19 a low cost total energy production basis. This is also 20 very standard practice, and, again, the energy cost of 21 running a large coal-fired plant includes the cost of this 22 extra capital in moving to a base load-type of unit, 23 there's a lot more capital wrapped up in one of those than 24 a peaking simple cycle CT, plus the running costs. Those 25 are the two elements of the energy cost, and that's 575 CSB REPORTING WEAVER (Com) Wilder, Idaho 83676 PacifiCorp 1 exactly what I've done here to convert the SAR total cost 2 into a realistic capital and energy component. Have I 3 answered your question, I hope. 4 Q Yeah, I would just say in response that you 5 don't sign contracts with any of those other sources for 6 6,000 hours a year worth of energy. 7 A Actually, we do sign contracts that call for 8 both capacity and energy, and when we sign such a 9 contract, the amount of energy that is to be generated, 10 delivered under those contracts, is specified and it's not 11 at all uncommon to have the capital -- I'm sorry, that's 12 what I don't want to do -- a capacity quantity specified 13 in the contract, a capacity price specified in the 14 contract, an energy quantity specified in the contract and 15 an energy price specified in the contract. Just like I 16 said here, those are not at all uncommon in the industry. 17 COMMISSIONER NELSON: Okay, thank you. 18 COMMISSIONER MILLER: Redirect. 19 MR. ERIKSSON: Nothing. Thank you. 20 COMMISSIONER MILLER: Mr. Weaver, thank you 21 very much for your help. 22 THE WITNESS: Thank you. 23 (The witness left the stand.) 24 MR. FELL: Mr. Chairman, there was one 25 question asked about those five-year energy rate only 576 CSB REPORTING WEAVER (Com) Wilder, Idaho 83676 PacifiCorp 1 numbers that were in Exhibit 63, this is a legal issue. 2 Those numbers reflect what is required to be made 3 available to the public under the FERC PURPA regulations, 4 18 Code of Federal Regulations, Section 292.302(b)1. No 5 witness has said that because they don't feel they should 6 be citing those things, but rather than wait to say that 7 in my brief, that is what that is. 8 COMMISSIONER MILLER: Well, we'll note that 9 observation for the record. Let's reconvene at 10 4:00 o'clock. 11 (Recess.) 12 COMMISSIONER MILLER: All right, Mr. Fell or 13 Mr. Eriksson. 14 MR. ERIKSSON: We call Mr. Morris. 15 16 17 18 19 20 21 22 23 24 25 577 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 KENNETH N. MORRIS, 2 produced as a witness at the instance of PacifiCorp, 3 having been first duly sworn, was examined and testified 4 as follows: 5 6 DIRECT EXAMINATION 7 8 BY MR. ERIKSSON: 9 Q Would you please state your name and 10 business address? 11 A Kenneth N. Morris, 1407 West North Temple, 12 Salt Lake City, Utah. 13 Q And your position with PacifiCorp? 14 A I'm manager of system transmission planning. 15 Q And have you in the scope of that position 16 prepared and had filed in this case direct testimony 17 consisting of 11 pages of narrative and five exhibits 18 numbered 116 through 121? 19 A Yes, I have. 20 Q And do you have any corrections -- I'm 21 sorry, that was 116 through 120. 22 A Yes, 120. 23 Q Any corrections to that? 24 A I do. On Page 5 of my testimony, on 25 Line 10, the Exhibit 118 should be 119. 578 CSB REPORTING MORRIS (Di) Wilder, Idaho 83676 PacifiCorp 1 Q And with that correction, if I were to ask 2 you the same questions today as are contained in your 3 testimony, would your answers be the same? 4 A Yes, they would. 5 MR. ERIKSSON: I'd ask that Mr. Morris' 6 testimony be spread on the record and the exhibits 7 identified as Exhibits 116 through 120. 8 COMMISSIONER MILLER: So ordered. 9 (The following prefiled testimony of 10 Mr. Kenneth Morris is spread upon the record.) 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 579 CSB REPORTING MORRIS (Di) Wilder, Idaho 83676 PacifiCorp 1 Q Please state your name, business address and 2 present position with PacifiCorp (the Company). 3 A My name is Kenneth N. Morris and my business 4 address is 1407 West North Temple, Salt Lake City, Utah. 5 I am manager of System Transmission Planning for 6 PacifiCorp. 7 Q Have you prepared an exhibit which shows 8 your education, business experience and duties at the 9 Company? 10 A Yes, Exhibit No. 116 provides that 11 information. 12 Q What is the purpose of your testimony in 13 this proceeding? 14 A I will address the impact that transmission 15 limitations have on the relationship between the 16 availability of new generation resources located on the 17 eastside of the Company's system, cogeneration and small 18 power production facilities located in Idaho in 19 particular, and the Company's ability to avoid costs 20 through the deferral of capital additions and the 21 displacement of existing resources. 22 I will briefly describe the Company's bulk 23 electrical system with emphasis on transmission 24 capabilities which set the upper limit on the Company's 25 ability to transfer resources from the eastside to the 580 Morris, Di PacifiCorp 1 westside of its system. I will show that under certain 2 conditions, particularly during off-peak hours, additional 3 generation located on the eastside of the Company's system 4 (Idaho/Utah/Wyoming) could not be operated without 5 curtailing existing lower cost generation due to 6 transmission limitations. This requires that the 7 8 / 9 10 / 11 12 / 13 14 15 16 17 18 19 20 21 22 23 24 25 581 Morris, Di PacifiCorp 1 Company determine the value of any additional generation 2 located on the eastside of its system on a case by case 3 basis. The evaluation will have to consider location, 4 size, operating characteristics, and timing of the 5 generation addition. 6 Q How would you characterize the Company's 7 bulk power system. 8 A For the purpose of this discussion, the 9 Company's bulk power system can be represented by two 10 major load/resource areas as depicted in Exhibit No. 117. 11 The westside (Northwest) area represents the Company's 12 system in the states of Oregon, Washington, Montana, 13 California, and northern Idaho (Sandpoint area). The 14 eastside includes Utah, Wyoming, and the UP&L service area 15 in southern Idaho. Transmission constraints limit the 16 Company's capability to transfer power between the two 17 major areas. In Exhibit No. 117, the 1415 MW by the line 18 that connects the areas represents the Company's firm 19 transfer capability in the transmission path connecting 20 the two areas. 21 Q Would you describe the basis for the 22 transmission transfer capability in the transmission path 23 shown on Exhibit No. 117. 24 A Yes, transfer capabilities are based on 25 contractual rights in transmission paths that have 582 Morris, Di PacifiCorp 1 recognized transfer ratings. The transmission path 2 ratings are determined from studies utilizing computer 3 simulations of the transmission system. The criteria that 4 are applied to the results are consistent 5 6 / 7 8 / 9 10 / 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 583 Morris, Di PacifiCorp 1 with standard utility engineering practice and in 2 particular the "WSCC Reliability Criteria for System 3 Design." The transmission path ratings are limited by one 4 or more of the following criteria: (1) first swing 5 voltage dip following loss of a system element, (2) 6 thermal overload due to the loss of a system element, (3) 7 steady-state thermal limitations with all elements 8 in-service, (4) post-disturbance voltage deviations 9 following loss of a system element. Contracts allocate 10 the transmission path rating among parties with transfer 11 rights in the path. The Company's contractual right 12 (transfer capability) is identified in Exhibit No. 117. 13 Q What are the principle contractual 14 limitations the Company faces in transferring power from 15 the eastside to the westside of its system? 16 A The transfer capability of 1415 MW east to 17 west shown in Exhibit No. 117 is a contractual right the 18 Company has with Idaho Power Company (IPC). The contract 19 provides the Company the firm transfer right to transfer 20 the output of the Company's ownership of the Bridger 21 Generating Station plus some of the Company's Wyoming 22 resources up to a total transfer schedule of 1415 MW. The 23 Company makes delivery to IPC at its points of 24 interconnection with IPC in eastern Idaho and IPC 25 transfers such power to points of interconnection with the Company in western Idaho. 584 Morris, Di PacifiCorp 1 Q Can you quantify the Company's resources 2 available in the Idaho/Utah/Wyoming area that could be 3 transferred on the transmission paths to serve loads in 4 the Northwest area? 5 A Yes, Exhibits No. 117 through 120 indicate 6 total requirements and total resources projected for the 7 years 1995 and 2000 during summer and winter off-peak load 8 periods. I have chosen summer and winter off-peak load 9 conditions to demonstrate a range of available resources 10 and load requirements on a seasonal basis. 11 This analysis is based on the area loads and 12 resources data presented by Dr. Weaver in Exhibit No. 113. 13 The numbers in each area represent total requirements 14 which include load, firm sales, exchange returns, and 15 reserves, and total resources which include Company owned 16 resources and firm purchases. The "net" is calculated by 17 subtracting the total requirements from the total 18 resources. When requirements are greater than resources, 19 there is a net requirement for additional resources in the 20 area and the net requirement is shown in parenthesis. 21 Exhibits No. 119 and No. 120 illustrate the 22 requirement and resource balances that are projected for 23 the year 2000 during winter and summer off-peak load 24 periods, respectively. Referring to Exhibit No. 119, 25 during winter off-peak load periods, resources exceed 585 Morris, Di PacifiCorp 1 total requirements by 2746 MW in the Idaho/Utah/Wyoming 2 area while there is a 2048 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 586 Morris, Di PacifiCorp 1 MW net requirement in the Northwest area. During summer 2 off-peak load periods, total resources exceed total 3 requirements by 2669 MW in Idaho/Utah/Wyoming area and 4 there is a corresponding net requirement in the Northwest 5 area of 1555 MW. 6 Q Is there a need in the Company's Northwest 7 area for the Idaho/Utah/Wyoming resources? 8 A Yes, as indicated by Dr. Weaver, there is a 9 significant need in the Northwest for resources during 10 off-peak hours. As shown in Exhibits No. 117 and 119, the 11 need for additional resources ranges from 2336 MW in 1995 12 to 2048 MW in the year 2000 for winter off-peak 13 conditions. Dr. Weaver describes the resources and 14 requirements on the east and west sides of the system 15 during off-peak periods. He shows that there is 16 substantial generation available on the east side to meet 17 westside requirements if sufficient firm transmission 18 capability is available. 19 Q What transfer capability does the Company 20 have to transfer Idaho/Utah/Wyoming resources to the 21 Northwest? 22 A As shown in Exhibit No. 117, firm transfer 23 capability is available to transfer 1415 MW from 24 Idaho/Utah/Wyoming to the Northwest. At the same time the 25 net requirement in the Northwest area for resources is 587 Morris, Di PacifiCorp 1 2336 MW and there are 2693 MW available in 2 Idaho/Utah/Wyoming for export. 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 588 Morris, Di PacifiCorp 1 During the 1995 summer off-peak periods, presented 2 in Exhibit No. 118, there is approximately 2678 MW of 3 resources available for transfer from the 4 Idaho/Utah/Wyoming area. The net requirement for 5 additional resources in its Northwest area is 1868 MW. 6 Q During these off-peak periods when the 7 Company's net requirements in the Northwest exceed the 8 Company's ability to transfer resources from the eastside 9 of its system, how does the Company meet its requirements? 10 A There are several options available to the 11 Company to meet Northwest requirements in excess of the 12 Company's firm east to west transfer capability. The 13 Company's wheeling agreement with Southern California 14 Edison Co. (SCE) allows the transfer of a fixed annual 15 amount of energy to the Northwest. The amount transferred 16 during any hour is at the sole discretion of SCE. 17 Non-firm wheeling paths are also available through members 18 of the InterCompany Pool (at approximately $1.50/MWh), or 19 through California utilities (approximately $6.00 MWh). 20 The Company can often purchase non-firm energy from 21 utilities in the Northwest, usually at a substantially 22 higher cost than Company owned eastside resources. 23 Finally, the Company can operate the power system in a 24 sub-optimal fashion by taking more energy from energy 25 limited resources in the Northwest (such as hydro) during heavy load hours and thus reduce the off-peak return 589 Morris, Di PacifiCorp 1 requirement to BPA. This ultimately increases the cost of 2 meeting retail requirements. 3 Q With these non-firm wheeling options 4 available to the Company, couldn't the Company accommodate 5 additional QF generation on the eastside of its system? 6 A No, it would not be in the best interest of 7 the Company's customers to increase its reliance on 8 non-firm wheeling to meet firm load obligation. Since 9 there is no major east to west transmission planned, there 10 is no reason to assume that more non-firm wheeling will 11 become available in the future. In fact, it is likely to 12 decrease as competition increases. The only sure way to 13 accommodate additional energy on the eastside during 14 off-peak hours is to curtail existing Company low cost 15 resources. Energy that relies on non-firm transmission 16 capability is itself non-firm and should not be paid firm 17 energy prices. 18 Q How would you expect the conditions you have 19 described to change over time? 20 A There are three factors that impact these 21 conditions: (1) load growth, (2) resource additions, and 22 (3) possible transmission additions between 23 Idaho/Utah/Wyoming and the Northwest. 24 Referring to Dr. Weaver's Exhibit No. 113, the net 25 resources available for transfer from Idaho/Utah/Wyoming remain relatively constant during the 5-year period. The 590 Morris, Di PacifiCorp 1 available eastside resources and the net westside 2 requirements exceed the transfer capability of the 3 transmission path to transfer the resources to the 4 Northwest area throughout this period. 5 The Northwest resources reported in Dr. Weaver's 6 Exhibit No. 113 reflect the addition of the purchase of 7 capacity and energy from the Hermiston generation project 8 (474 MW) in 1996. This resource addition reduces the 9 magnitude of the need for resources to be transferred from 10 the Idaho/Utah/Wyoming area into the Northwest area. 11 However, during off-peak load periods, the resource 12 requirement in the Northwest area continues to be greater 13 than the transfer capability from Idaho/Utah/Wyoming to 14 the Northwest. 15 The addition of major transmission could 16 significantly increase the ability to utilize existing and 17 new Idaho/Utah/Wyoming resources to meet Northwest 18 requirements. However, there is no current plan to 19 construct major transmission for this purpose. 20 Q If new transmission were constructed, what 21 would it likely cost? 22 A Transmission additions occur in discrete 23 sizes (voltage class and rating), that is, 500 kV, 24 345 kV, or 230 kV lines, which have capacities 25 corresponding to their physical characteristics. Due 591 Morris, Di PacifiCorp 1 to the distances involved from Idaho/Utah/Wyoming to 2 the Northwest, it is likely that a 500 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 592 Morris, Di PacifiCorp 1 kV transmission line would be required for economic as 2 well as environmental reasons. A 500 kV line would have 3 approximately 1000 MW of capacity. The approximate cost 4 of such a line would be in excess of $500 million. 5 Q What is the impact of adding additional 6 generation in the Idaho/Utah/Wyoming area without 7 additional transmission? 8 A To the extent that the resource additions 9 exceed load growth in the Idaho/Utah/Wyoming area, the 10 amount of energy and capacity that is constrained due to 11 transmission limitations increases. If the additions are 12 less than load growth, the constrained capacity will 13 decrease over time. As I previously stated in reference 14 to Dr. Weaver's Exhibit No. 113, the projection for the 15 next 5 years is that resources in excess of requirements 16 in the Idaho/Utah/Wyoming area will remain at a fairly 17 constant level. Any additional eastside resource would 18 add to the projected "bottlenecked" energy I have 19 described. This "bottleneck" condition will not be 20 eliminated until the combination of eastside requirements 21 and east to west transfers falls below the level of 22 eastside resources. 23 Q You have described the Company's 24 transmission constraint between the eastside and westside 25 of its system. Given this constraint, does the Company operate as a single integrated system? 593 Morris, Di PacifiCorp 1 A Yes. The Company operates as a "single 2 integrated system" within its transmission limitations. 3 The Company schedules all of its generation, purchases, 4 and sales to meet its total system requirements in an 5 economical and reliable manner from one scheduling office. 6 There are times when schedules of specific resources must 7 be restricted due to transmission limitations. 8 Any utility can face operating restrictions due to 9 transmission limitations. Because of the distances 10 involved in the Company's system, PacifiCorp may be unique 11 in the magnitude of the investment required to reduce or 12 eliminate its limitations. 13 Q Prior to the UP&L/PP&L merger did PP&L 14 operate as a "single integrated system"? 15 A Yes. Prior to the UP&L/PP&L merger, there 16 was a westside area (California, Oregon, Washington, 17 Montana, northern Idaho) and an eastside area 18 (PP&L-Wyoming). There was one scheduling office that 19 scheduled all of PP&L's generation and purchases/sales to 20 meet total PP&L system requirements in an economical and 21 reliable manner. 22 Q Did transmission limitations exist in the 23 PP&L system prior to the UP&L/PP&L merger? 24 A Yes. There were times, primarily during 25 off-peak load periods, that PP&L resources located in Wyoming could not be 594 Morris, Di PacifiCorp 1 operated at full capacity because of transmission 2 limitations between Wyoming and the Northwest. 3 Q How do the economic considerations of a 4 qualifying facility affect the constrained energy? 5 A Since a qualifying facility (QF) receives 6 payments for the amount of energy produced, it is in the 7 QF's best interest to produce as much energy as possible. 8 If the QF produces energy in addition to the Company's net 9 resources that exceeds the transfer capability out of the 10 area, then the Company's resources must be curtailed. 11 Therefore, during the off-peak constrained hours, the QF 12 hasn't added any usable generation capacity to the system. 13 The energy delivered by the QF would be equal in value 14 during the constrained hours to the incremental fuel cost 15 of the Company owned generation that would have to be 16 curtailed. This would be the avoided cost of such QF 17 resources during those hours. 18 Q Does this conclude your direct testimony? 19 A Yes. 20 21 22 23 24 25 595 Morris, Di PacifiCorp 1 (The following proceedings were had in 2 open hearing.) 3 MR. ERIKSSON: And I just have a few 4 surrebuttal questions to ask of Mr. Morris. 5 6 DIRECT EXAMINATION 7 8 BY MR. ERIKSSON: (Continued) 9 Q Mr. Morris, have you read Dr. Slaughter's 10 rebuttal testimony? 11 A Yes, I have. 12 Q And turning to Pages 14 and 15 of that 13 testimony, Dr. Slaughter refers to some transmission lines 14 identified by WSCC which he characterizes as planned 15 transmission additions to PacifiCorp's system as well as 16 an Idaho Power line from Midpoint to the Southwest. Are 17 you familiar with those lines? 18 A Yes, I am. 19 Q On Page 14, he says that they appear to tie 20 into the Southwest market. If they were built, would they 21 tie into the Southwest market? 22 A Of the lines that are listed there, the 23 Idaho line, the Southwest intertie line, would connect 24 Midpoint and an area south of -- well, actually, now it's 25 north of Las Vegas which would be considered Southwest, 596 CSB REPORTING MORRIS (Di) Wilder, Idaho 83676 PacifiCorp 1 and the Sigurd to Glen Canyon line is also a line that 2 would tie to the Southwest. 3 Q What's the status of the Sigurd line? 4 A The Sigurd line as well as most of these 5 lines on here, except for the Miners-Foote Creek line, are 6 very tentative. The Sigurd-Glen Canyon line will not 7 appear in the next document that Dr. Slaughter referenced, 8 the WSCC significant additions report, and the Emery-Green 9 River and Green River-Grand Junction are really one line. 10 The Green River is a substation in the middle of that 11 project. That line also was originally reported by 12 PacifiCorp and will not be reported by PacifiCorp in the 13 next report. 14 The Terminal to Stateline project, really, 15 Stateline is just where the line crosses the Utah-Nevada 16 border. It really goes on to Wells, Nevada. That line 17 simply is put in as a tentative project. We're doing a 18 little bit of feasibility in terms of right of way to see 19 if the line could even be built if it were justified. It 20 goes through the Dougway Bombing Improving grounds and so 21 there's some question of whether or not that line could be 22 built. 23 I'd like to just say that the report that 24 Dr. Slaughter referenced, the WSCC report, just so you 25 understand the nature of the lines in there, he prefaced 597 CSB REPORTING MORRIS (Di) Wilder, Idaho 83676 PacifiCorp 1 his exhibit with a title page which I think doesn't 2 accurately capture what this report is meant to say. It 3 says it's the WSCC Transmission Construction Report, which 4 it really isn't. I'd like to read, if I could, just from 5 the forward to that report just so you understand the 6 nature of what's reported in this type of report. 7 MR. ORNDORFF: I'd like to inquire, 8 Mr. Chairman, is this going to be an exhibit? I don't 9 believe the forward is in Dr. Slaughter's exhibit. 10 COMMISSIONER MILLER: Mr. Eriksson. 11 MR. ERIKSSON: I don't think it needs to 12 be. Mr. Morris can simply testify as to what is reported 13 in the WSCC document. 14 COMMISSIONER MILLER: All right, we'll allow 15 him to do that on the condition that the full document is 16 shown to Mr. Orndorff to aid in his cross-examination if 17 he desires. 18 MR. ERIKSSON: Thank you. 19 THE WITNESS: Basically, what I wanted to 20 say is the direction under which items are to be reported 21 in this report to WSCC are both tentative as well as 22 committed projects and these are basically tentative 23 projects, except for the Miners-Foote Creek which is a 24 29-mile line in the State of Wyoming that doesn't 25 interconnect to anyone. It's an internal line to 598 CSB REPORTING MORRIS (Di) Wilder, Idaho 83676 PacifiCorp 1 PacifiCorp, and I don't want to be misrepresented by 2 saying that I'm saying the SWIP line, Idaho's line, is 3 tentative. They'll have to speak to that for themselves. 4 I'm not making any representation as to their line and how 5 committed it is. 6 Q BY MR. ERIKSSON: If that line were built, 7 that is, what you referred to as the SWIP line, is that 8 the Idaho Power line referred as the Midpoint to, well, 9 Midpoint, Idaho to the Southwest market? 10 A That's right. SWIP stands for Southwest 11 intertie project. 12 Q If that line were to be built, would that 13 allow the Company to alleviate the constrained east side 14 energy during the off-peak hours? 15 A No, we have no plans to participate in that 16 line and have no direct rights to get to Midpoint. 17 Q Is Dr. Slaughter correct in saying that 18 these lines are expected to be operating prior to Rosebud, 19 which I take it to mean 1999? 20 A Again, in the report, they did show 21 in-service dates of December, '98 and December, '99. 22 Those were strictly just a date to put in for study 23 purposes, and as I've said, except for the Miners-Foote 24 Creek, they're really not committed projects; so I would 25 fully anticipate they will not be in-service by those 599 CSB REPORTING MORRIS (Di) Wilder, Idaho 83676 PacifiCorp 1 dates shown there. 2 Q Turning to Page 16 of Dr. Slaughter's 3 testimony, that is, his rebuttal testimony, Line 6, 4 he states that you originally testified that there would 5 be no avoidable transmission integral with an SAR located 6 in PacifiCorp's service territory in the 170 case, and 7 then goes on to state that the Commission rejected that 8 contention. Is that an accurate characterization of what 9 occurred? 10 A No. Those are really two unrelated items. 11 During the course of that hearing, I did acknowledge that 12 there would be some avoidable transmission associated with 13 the SAR in the Powder River Basin so there was no need for 14 the Commission to reject that contention. This quote in 15 Dr. Slaughter's testimony is related to the weighting 16 factors that would be applied to my calculation of sort of 17 a surrogate transmission line. 18 MR. ERIKSSON: Okay, that's all I have and 19 he's available for cross. 20 COMMISSIONER MILLER: Cross-exam. 21 22 23 24 25 600 CSB REPORTING MORRIS (Di) Wilder, Idaho 83676 PacifiCorp 1 CROSS-EXAMINATION 2 3 BY MR. ORNDORFF: 4 Q Mr. Morris, what's the nearest generating 5 resource to the largest city you have in eastern Idaho in 6 your service area? 7 A The largest city that we have? 8 Q Do you know what the largest city is in the 9 service area? 10 A From our load standpoint? 11 Q Uh-huh. 12 A I don't know the exact -- it would be in the 13 Rexburg area. 14 Q Are you familiar with the service area at 15 all? 16 A Reasonably. 17 Q Do you know what the large cities are in the 18 service area? 19 A I don't know the populations. 20 Q I'm talking about loads. What's your 21 largest load, firm load? 22 A It's the Rexburg area. 23 Q What's the nearest generating resource to 24 Rexburg that PacifiCorp has now? 25 A I could tell you that it's not very large. 601 CSB REPORTING MORRIS (X) Wilder, Idaho 83676 PacifiCorp 1 Q Maybe I can make this easier, Mr. Morris. 2 What's the nearest 40 megawatt or larger resource you 3 have? 4 A To the Rexburg area? 5 Q Yeah, where your loads are. 6 A That would be probably Notten. 7 Q How many transmission miles is that, 8 roughly? 9 A This would just be an estimate. 10 Q Sure. 11 A Oh, probably, I'll say 150. 12 Q How many transmission miles is it to the 13 Ovid substation? 14 MR. ERIKSSON: Could we have that clarified 15 whether or not that's from the Ovid substation to the 16 Rexburg area or to Notten? 17 MR. ORNDORFF: No, to the load center at 18 Rexburg. 19 THE WITNESS: It could be probably not more 20 than 50 miles. 21 Q BY MR. ORNDORFF: Generally, in the 22 transmission business, Mr. Morris, does fewer miles equate 23 to less line losses? 24 A Generally speaking. It depends on kind of 25 the prevailing flow, I guess. Sometimes you add 602 CSB REPORTING MORRIS (X) Wilder, Idaho 83676 PacifiCorp 1 generation, it will add to the flow. Sometimes it will 2 decrease the flow. 3 Q Isn't it typical that you try to match your 4 resources with your loads as far as minimizing your 5 transmission costs? 6 A That is to minimize transmission costs. 7 There's generally, of course, as you understand, other 8 overriding factors. 9 Q Is there a 40 megawatt resource in the Idaho 10 service area? 11 A Not one unit that's 40 megawatts. 12 Q Is there a combination of units that you buy 13 in the Idaho service territory that total 40 megawatts? 14 A I'm not sure. We have several small hydro 15 units, but they probably don't add over 40. 16 Q Anywhere close to 40? 17 A Probably in the less than 20. 18 Q Are you familiar with the Energy Policies 19 Act of 1992 and the openness access provisions? 20 A Only generally, not specific. 21 Q Have you received an open access request? 22 A I believe we received a request, but I don't 23 believe the clock has started on it. It may have been 24 withdrawn; so I'm not quite sure how to answer that, if 25 there's an active request before us or not. I guess I'm 603 CSB REPORTING MORRIS (X) Wilder, Idaho 83676 PacifiCorp 1 not aware that there is one. 2 Q In wheeling your power to the Southwest, 3 what is the charge on an open access fully embedded cost? 4 A I'm not sure what our current rate is. 5 Q The resources are, though, marketed by 6 PacifiCorp on a normal basis; is that right? 7 A We market resources, yes. 8 Q Do you market Montana Power's power from 9 Colstrip? 10 A I'm not aware that we market for a third 11 party. 12 Q You do wheel it, though, don't you? 13 A There is an intercompany pool agreement for 14 some non-firm wheeling, but sometimes we may wheel for 15 them. I'm not aware directly of any times we have done. 16 MR. ORNDORFF: That's all I have, 17 Mr. Chairman. 18 COMMISSIONER MILLER: Commissioner Nelson. 19 COMMISSIONER NELSON: Not for me. Thank 20 you. 21 COMMISSIONER MILLER: Redirect. 22 MR. ERIKSSON: If I could approach the 23 witness and show him a document which may help to answer a 24 question regarding additional generation in the Idaho 25 area. 604 CSB REPORTING MORRIS (X) Wilder, Idaho 83676 PacifiCorp 1 COMMISSIONER MILLER: Certainly. 2 MR. ORNDORFF: Could I have a copy of that, 3 Mr. Chairman? 4 COMMISSIONER MILLER: Show it to 5 Mr. Orndorff first. 6 (Mr. Eriksson approached the witness.) 7 8 REDIRECT EXAMINATION 9 10 BY MR. ERIKSSON: 11 Q Mr. Morris, does the Company have hydro 12 generation in the Idaho area and northern Utah? 13 A Yes, it does. 14 Q And is that generation in excess of 15 40 megawatts nameplate rating? 16 A Yes, in total it is. There's the Grace 17 plant at 33 megawatts, the Oneida at 30 megawatts for a 18 total of 66 megawatts. 19 Q Others as well? 20 A And Soda is 14 megawatts. 21 MR. ERIKSSON: That's all I have. 22 COMMISSIONER MILLER: All right, Mr. Morris, 23 thank you for your help. 24 (The witness left the stand.) 25 MR. ERIKSSON: May he be excused? 605 CSB REPORTING MORRIS (Di) Wilder, Idaho 83676 PacifiCorp 1 COMMISSIONER MILLER: Certainly. 2 (Off the record discussion.) 3 COMMISSIONER MILLER: All right, I think we 4 can go back on the record. It's my impression that we're 5 now concluded with the evidentiary presentations. We have 6 a couple of exhibit question marks that still, at least 7 according to my notes, need to be resolved. There's the 8 question with respect to Exhibit 60, and then from my 9 notes yesterday, I thought there was going to be further 10 foundation or identification of Exhibits 121 and 123. I 11 don't know if in your view that has occurred or not 12 occurred or whether it's critical one way or the other. 13 MR. ORNDORFF: I will not object to the 14 admission of 121 and 123. 15 COMMISSIONER MILLER: All right, since 16 there's no objection, those two will be admitted. We do 17 then have Exhibit 60. I guess the way to start this is I 18 could give you my thought on it and then each party could 19 respond. It seems to me that Exhibit 60 is offered to 20 show, at least for one purpose, that PacifiCorp knew that 21 the project was of sufficient maturity so as to entitle it 22 to the right of substantive negotiations, but that 23 notwithstanding that knowledge, PacifiCorp engaged in a 24 course of conduct designed to prevent or thwart 25 substantive negotiations, and if my understanding of the 606 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 purpose for which it's offered is correct, it seems to me 2 a necessary foundation is a showing that the document 3 actually came into the possession or knowledge of 4 PacifiCorp and at this point that's denied by PacifiCorp 5 and as far as I can tell there is no independent proof 6 that would contravene the denial and allow it to be 7 entered into evidence. That's how I'm thinking about it 8 right now. 9 MR. ORNDORFF: Well, Mr. Chairman, I only 10 have one problem with that analysis and that is that the 11 Staff was involved in this discussion, it has been ongoing 12 for over a year, and they received their copy, they 13 certainly had it in their files. PacifiCorp was here for 14 at least four prehearing conferences. The Staff files, 15 they're not closed. You know, it's unfortunate that 16 PacifiCorp doesn't have their copy, but query when a QF 17 makes a good showing, sends it to the Staff, sends it, I 18 certainly allege I sent it out and they have part of it, 19 there are two parts. They can't prove they didn't lose it 20 just like I can't prove for sure I sent out two parts, and 21 the best indication that the two parts went out is the 22 Staff has both parts. 23 COMMISSIONER MILLER: It sounds to me 24 like -- we'll let Mr. Fell respond, but it sounds to me 25 like the factual question of whether there is sufficient 607 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 other circumstantial evidence of delivery that would 2 permit an inference that it was more likely than not 3 delivered is probably a question of fact that the 4 Commission should deliberate on as part of its overall 5 decision in the case rather than the Chair ruling as an 6 evidentiary matter now. I think we understand what the 7 circumstantial evidence surrounding the question is; so 8 we'll let Mr. Fell have a concluding comment, but I would 9 propose not to rule on the admission of the exhibit. 10 We'll include that as part of our deliberations in the 11 case as this does appear to be a disputed factual issue; 12 so, Mr. Fell, what would you like to say to us? 13 MR. FELL: I'm satisfied with withholding 14 the ruling. If there's anything that the record in this 15 case has to offer, we can address it in our briefs. I 16 don't believe it's appropriate to use, to attribute 17 knowledge to PacifiCorp on the basis of what was given to 18 the Staff, particularly a Staff attorney. We do not ever 19 ask to review Staff attorney files, nor do we know when 20 the Staff might have gotten their copy. Maybe the Staff 21 copy has a date on it, but that hasn't been brought up 22 either. In any case, the real material issue here is 23 whether PacifiCorp had it and from our perspective, there 24 were plenty of opportunities that were available if 25 Rosebud had met with us to talk about the facts of the 608 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 generation that we surely would have started going through 2 that, but time and again they did not want to do that. 3 COMMISSIONER MILLER: Well, we'll confine 4 our decision on this point, obviously, to the record as 5 it's been developed and determine whether to admit 6 Exhibit 60 when we engage in our subsequent 7 deliberations. All right, that takes care of the exhibits 8 then. There remains, there have been hints throughout 9 that the parties would like the opportunity for 10 posthearing submissions. 11 MR. ORNDORFF: There's one other matter, 12 Mr. Chairman. You asked for a rendition of the two 13 projects and how they all fit together. Is that still of 14 interest or did we get that clarified to your 15 satisfaction? 16 COMMISSIONER MILLER: I think at this point 17 the Commission now has a clear view of those 18 circumstances. 19 MR. ORNDORFF: That's fine. 20 MR. FELL: We should also note that 21 Exhibit 130 was not admitted; so that if there's a blanket 22 admission of exhibits, it does not include 130. 23 COMMISSIONER MILLER: Let's at this point, 24 then, for the record admit all the exhibits with the 25 exception of 130 and with the observation that the 609 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 Commission is reserving its ruling on Exhibit 60. 2 (All exhibits previously marked for 3 identification, with the exception of Exhibits 60 and 130, 4 were admitted into evidence.) 5 COMMISSIONER MILLER: Now, are we ready to 6 discuss briefs? What would the parties desire in terms of 7 a schedule? 8 MR. FELL: Mr. Chairman, we have an avoided 9 cost hearing coming up next week which is a surprise to 10 everybody. The court reporter will need to get the 11 transcript out and if we could start perhaps with some 12 idea of when the transcript will be ready, we could work 13 from that. We will want opening and reply briefs so that 14 we can respond to Rosebud's brief. 15 MR. ORNDORFF: Mr. Chairman, I believe I'm 16 the Complainant in this case and I don't believe 17 PacifiCorp gets a reply to my -- I mean, if we're going to 18 do opening briefs, I file, the normal custom is we file a 19 brief, they file a brief. I mean, are we going to go 20 through the briefing cycle in a rotation? That seems to 21 me to be taking it to the extreme. I mean, I normally get 22 the opening brief and the closing brief if we're going to 23 do it that way. They don't get the last reply. I know 24 they'd like it, but that's not normally how it's done. 25 COMMISSIONER MILLER: Let's take this one 610 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 step at a time. Let's start with, Madam Reporter, your 2 estimate of when the transcript will be available. 3 THE REPORTER: It will be available next 4 week. I can't give you a specific day, probably Wednesday 5 or Thursday. 6 MR. FELL: So we would have it by the end of 7 the week. 8 COMMISSIONER MILLER: Let's assume 9 transcript availability by Friday. All right; so that's 10 when the clock starts. How much time do we need for 11 simultaneous opening briefs? Let's see, that's 12 December 2nd? 13 MR. FELL: Friday is December 2nd? So if we 14 had two weeks, that would go to December 16, and I often 15 do a lot of brief writing on weekends; so what I would 16 like is Tuesday after that. There is a significant record 17 here. 18 COMMISSIONER MILLER: So that would be 19 Tuesday, what date? 20 MR. FELL: I think it's the 20th. Tuesday 21 is the 20th. 22 MR. ORNDORFF: Mr. Chairman, I'd inquire 23 just generally what the decision meeting schedule is 24 before we have maybe a change in the Commission and maybe 25 we should work backwards as to how we set the schedule. 611 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 There is a very substantial record and it would seem to be 2 a waste to be in a briefing schedule where the people that 3 are making the decision aren't on the Commission; so 4 perhaps working backwards would be a better way to 5 approach it. 6 COMMISSIONER MILLER: Well, we're going to 7 have to decide this case sometime in the first days of 8 January. 9 COMMISSIONER NELSON: I'm available. 10 COMMISSIONER MILLER: What would two weeks 11 after the 20th be? 12 MR. FELL: That would be January 3rd and I 13 think January 2nd is probably a holiday; so if it were the 14 next day, that would allow us to get it delivered. We 15 could get an overnight delivery Tuesday and file 16 Wednesday. 17 COMMISSIONER MILLER: Wednesday the 4th? 18 MR. FELL: Yes. Actually, 1, 2, 3, 4, yes. 19 COMMISSIONER MILLER: Well, the Commission, 20 of course, will try to decide this within the first 10 21 days or so of January. Since it's a fully submitted and 22 contested matter, we are permitted by law to deliberate it 23 outside of a public meeting. I'm assuming the Staff help 24 that we receive on this could be in-progress so that if we 25 receive the final reply briefs from both parties on the 612 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 4th, we'll be in a position where we can read those, 2 integrate that into the work we've done up until then and, 3 hopefully, get something out almost immediately after 4 that. 5 I think what I would suggest is simultaneous 6 reply briefs. Each party would have a reply opportunity 7 to address the briefs of the others; so if that's 8 agreeable, we will set Tuesday the 20th as the date for 9 the filing of the initial briefs, Wednesday the 4th as the 10 date, January 4th as the date, for simultaneous reply 11 briefs if they're desired. Is that agreeable with 12 everyone? 13 MR. FELL: That is agreeable. 14 MR. ORNDORFF: Yes, Mr. Chairman. 15 COMMISSIONER MILLER: What else needs to 16 come before us then? If nothing, thanks for your 17 dedicated effort in this case and the effort to ensure 18 that the Commission has a full record. We'll be adjourned 19 and issue our decision as soon as it's possible for the 20 Commission. 21 (The Hearing concluded at 4:35 p.m.) 22 23 24 25 613 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 AUTHENTICATION 2 3 4 This is to certify that the foregoing 5 proceedings held in the matter of Rosebud Enterprises, 6 Inc., Complainant, versus PacifiCorp, dba Utah Power & 7 Light Company, Respondent, commencing at 9:30 a.m., on 8 Monday, November 21, and continuing through Tuesday, 9 November 22, 1994, at the Commission Hearing Room, 10 472 West Washington, Boise, Idaho, is a true and correct 11 transcript of said proceedings and the original thereof 12 for the file of the Commission. 13 Accuracy of all prefiled testimony as 14 originally submitted to the Reporter and incorporated 15 herein at the direction of the Commission is the sole 16 responsibility of the submitting parties. 17 18 19 20 CONSTANCE S. BUCY Certified Shorthand Reporter #187 21 22 23 24 25 614 CSB REPORTING AUTHENTICATION Wilder, Idaho 83676