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HomeMy WebLinkAboutROS12152.txt 1 BOISE, IDAHO, WEDNESDAY, DECEMBER 15, 1993, 1:30 P. M. 2 3 4 COMMISSIONER MILLER: Let's note for the 5 record or let's go back on the record and note that 6 Mr. Orndorff has now distributed Exhibit Nos. 11 and 12 7 which we will mark at this point. 8 (Rosebud Enterprises, Inc. Exhibits 11 & 12 9 were marked for identification.) 10 MR. KLINE: Mr. Chairman, I do have one 11 preliminary matter that I would like to raise at this point. 12 COMMISSIONER MILLER: Yes, sir. 13 MR. KLINE: It may affect scheduling, I 14 guess. Earlier this morning, Mr. Woodbury distributed to us 15 copies of some changed testimony for Staff witness Faull, 16 and the change, I think even the Staff witness would agree, 17 is a very substantial change, and, quite frankly, we are not 18 going to have adequate time having received it only this 19 morning to be able to prepare for it in time to conduct 20 proper cross-examination; so I'm going to request that 21 Mr. Faull be made available for Idaho Power's 22 cross-examination at least tomorrow morning so that we'll 23 have adequate time to do that. If Scott wants -- if you 24 have any questions about the content that necessitates the 25 changed testimony, I'll let Scott respond to that. 308 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 COMMISSIONER MILLER: I think we've been at 2 least informally advised the general nature of it. 3 MR. WOODBURY: I only spoke to -- 4 COMMISSIONER NELSON: All he did was reverse 5 his position? 6 COMMISSIONER MILLER: Why don't you explain it 7 for us, Mr. Woodbury. 8 MR. WOODBURY: What we're submitting is three 9 replacement pages, 19, 20, and 21. The changes reflect -- 10 if I can approach the Bench, these are replacement pages to 11 Tom Faull's direct testimony. 12 (Mr. Woodbury approached the Bench.) 13 MR. WOODBURY: On Page 19, the answer on 14 Lines 19 through 24 is deleted, and on Page 20, the top 15 three lines are deleted. Substitute language is added, 16 replacement Pages 19 and 20. 17 On Page 21, a sentence is added to the answer 18 at Line 11 as reflected in replacement Page 21. Also, the 19 answer, Lines 17 to 24, second and third paragraphs are 20 deleted and substitute language as reflected in replacement 21 Page 21 is substituted. The nature of the change is based 22 upon the Staff review of correspondence in the case, all of 23 which correspondence was not apparently in the work file 24 that Staff used. I guess we view Rosebud's commitment and 25 entitlement to a contract differently than we did in the 309 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 original testimony. 2 MR. KLINE: Mr. Chairman. 3 COMMISSIONER MILLER: Mr. Kline. 4 MR. WOODBURY: And we could address that, I 5 guess, in greater detail when Tom takes the stand. 6 MR. KLINE: One other I guess fall-out of the 7 fact that this change in the testimony has come at the 8 eleventh hour is that we did not have an opportunity in any 9 of our direct testimony to respond to this position; so in 10 addition to having a chance to do some cross-examination 11 based on the actual testimony that's going to be presented, 12 we'd also like the opportunity to make a statement or 13 perhaps expand the testimony of our witnesses perhaps at the 14 conclusion of our case to address this specific issue. I 15 haven't really figured out exactly how we want to do that, 16 but we want to make sure that you know that that would be 17 something that we'd like to do. 18 MR. WOODBURY: Mr. Chairman, I think from the 19 standpoint of the length of the hearing that it's probably a 20 wash because I think it shortens the testimony of Rosebud. 21 COMMISSIONER MILLER: Well, I guess I would 22 propose that we essentially deal with that when it actually 23 comes up, but I think we would be inclined to allow whatever 24 is within reason in terms of an opportunity to prepare for a 25 response to this new testimony; so we'll just see how things 310 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 develop in terms of time and how we can accommodate it. 2 MR. WOODBURY: I think perhaps I misspoke when 3 I said the testimony of Rosebud. I know that Owen doesn't 4 testify, he just cross-examines. 5 COMMISSIONER MILLER: We'll see. 6 MR. FELL: Mr. Chairman and Mr. Woodbury, 7 could we distribute that testimony to others now? We 8 haven't received a copy of it. If we could just get a copy 9 of those pages. 10 MR. WOODBURY: I gave you a copy this morning. 11 MR. FELL: You mentioned it to me. 12 (Off the record discussion.) 13 COMMISSIONER MILLER: All right, let's go back 14 on the record and go to Mr. Woodbury for continued cross. 15 MR. WOODBURY: Thank you, Mr. Chairman. 16 17 18 19 20 21 22 23 24 25 311 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 RICHARD A. SLAUGHTER, 2 produced as a witness at the instance of Rosebud 3 Enterprises, Inc., having been previously duly sworn, 4 resumed the stand and was further examined and testified as 5 follows: 6 7 CROSS-EXAMINATION 8 9 BY MR. WOODBURY: (Continued) 10 Q Mr. Slaughter, your testimony at Page 9, you 11 reference an Exhibit 7 which is a resource stack for Idaho 12 Power Company. Could you indicate where the source of that 13 information came from and are all of the -- well, let me 14 start with that question. 15 A The source? 16 Q Yes. 17 A I apologize for not having that on there. The 18 basic source of the data is the 1993 integrated resource 19 plan. The two far right-hand columns, I think, are mine. 20 Q The integrated resource plan, is this a full 21 depiction of the Company's resources as it has set them out 22 in its resource plan? 23 A Is this a full exposition? 24 Q Yes, exposition. 25 A I don't remember, Mr. Woodbury. I could go 312 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 back and -- 2 Q You haven't deleted any resources, to your 3 knowledge? 4 A I don't think so, but it's been five months 5 since I did this. I can go back and pull up the plan and 6 compare it. 7 Q Fine. Moving on a little bit, on Page 15 of 8 your direct testimony, you sort of summarize, you say, "For 9 the Commission to delegate to Idaho Power its responsibility 10 for setting avoided cost would subject the ratepayer to a 11 high degree of potential manipulation and abuse," and then 12 you state that the avoided costs for all projects must be 13 set by the Commission, not the Company. 14 For purpose of clarification as far as setting 15 the rates for all projects, is it your understanding that 16 the rates for the recent Meridian contract and the Auger 17 Falls contract were previously set by the Commission or the 18 Commission approved the contracts with those rates? 19 A I believe the Commission approved a contract 20 between the parties and the intent of the paragraph is to, 21 is not to denigrate the Company, but it is to indicate that 22 the basic avoided cost rate has to start with Commission 23 approved procedures, Commission approved orders, rather than 24 internal Company processes that have not been subject to the 25 review of the Commission, have not been subject to the 313 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 review of the Commission in an adversarial proceeding. 2 Q Moving along to your rebuttal testimony, on 3 Page 6, Line 13, under your heading "Combined Cycle 4 Combustion Turbines and Ratepayer Risk," you state that 5 combined cycle combustion turbines are inappropriate for the 6 surrogate avoided resource. Did you not indicate last week 7 in Water Power's E-93-10 case before this Commission that 8 it's quite possible that a CCCT should be the surrogate? 9 A I believe what I indicated is that -- 10 MR. KLINE: Mr. Chairman, I'm going to object 11 to that. I think that's injecting into the case a record 12 that we've not seen, that we didn't participate in, have no 13 way of verifying. 14 COMMISSIONER MILLER: Mr. Woodbury, I wasn't 15 clear on where you were in the rebuttal testimony. What 16 page and line number are you on? 17 MR. WOODBURY: I believe Page 6, Line 13. The 18 answer starts with "Combined cycle CTs..." The last 19 sentence, "As such, they are inappropriate for the surrogate 20 avoided resource." My question to Mr. Slaughter is has he 21 given this any additional thought and is he still of that 22 opinion. 23 COMMISSIONER MILLER: I think the question is 24 probably allowable. It kind of goes to a potentially 25 inconsistent statement. 314 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 THE WITNESS: Mr. Woodbury, we had a lot of 2 discussion last week about combined cycle CTs and the risk 3 of gas and the pricing of gas and other related issues. I 4 think what I indicated in response to the questioning last 5 week was that the Commission may well adopt a combined cycle 6 CT in some form as a surrogate resource. 7 It continues to be my recommendation that 8 because of the gas price risks, because of differences in 9 the nature of the construction of the plants, because of 10 differences in the kinds of contracts that are typically 11 available and in place for fuel supply for the resources 12 that a combined cycle CT is a somewhat riskier SAR than a 13 coal-fired CT, and I say that without having run the current 14 numbers on a coal-fired SAR -- I'm sorry, I think I said 15 coal-fired CT, but a coal-fired SAR -- without having run 16 the numbers on a coal-fired SAR with today's inflation 17 expectations. I think we would find if we ran those numbers 18 that the differences in costs weren't nearly as great as has 19 been discussed in this Hearing Room. 20 Q BY MR. WOODBURY: Referring to your testimony 21 around Page 5, Line 8, you're again speaking of combined 22 cycle CTs and you reference a Northwest Power Planning 23 study, I guess, and your conclusion was that combustion 24 plants are essentially peaking and cycling units and not 25 base load. Is that still your belief? 315 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 A That is my impression from reading the 2 Northwest Power Planning Council's 1991 report, that their 3 use of -- and it's from that basis, not from an engineering 4 basis. The Council in its draft report presents a stack or 5 in its report presents a sizeable stack of potential 6 resources. Two of the resources in the stack are combined 7 cycle CTs and they are discussing as hydrofirming resources, 8 which I would expect to be cycling and peaking, not as base 9 load resources, and as we discussed last week, the Council 10 also recommended a number of -- that insurance be purchased 11 by means of hedging the use of those resources through 12 potential coal gasification and other measures. 13 Q You state that their inclusion as base load 14 units has the effect of shutting out competing fuels and 15 shifting risk to the ratepayer. 16 A Yeah. 17 Q Could you elaborate a little bit on that? 18 A A gas-fired resource relative to a solid fuel 19 resource has much more lower capital costs and it at least 20 at this point is anticipated to have much higher fuel costs 21 over the life of the resource, with the rate of inflation 22 from today's gas price estimated in various places of 23 between 5, 5.5 and 7.5 percent per annum over the next 24 35 years. If the -- and this sort of also gets beyond 25 what's in the testimony here, but in that case, Mr. Faull 316 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 presented an alternative proposal for a renewable resource 2 rate in which he captured the fuel inflation from gas into 3 the fixed cost of the contract, and my preliminary judgment 4 would be that if that were done with those inflation costs 5 that it's probably a workable, it's a workable rate for a 6 renewable kind of resource. 7 If that isn't done, and the point of this 8 particular testimony, if that isn't done, then the developer 9 faces a capital or fixed rate that is based, that is 10 predicated on very low capital costs of a gas-fired plant. 11 If he is building a plant that is designed for solid fuel, 12 his capital costs are going to be higher; so in order to 13 meet his debt service and pay his expenses, he's going to 14 have to, in fact, he's wagering that the anticipated 15 inflation will happen. The developer is wagering on that 16 and the bank is wagering on that. It's my expectation that 17 the bank won't do that. The developer's financiers probably 18 won't do that whatever the developer may choose to do, and 19 as a result, the resource won't get built and the ratepayers 20 wouldn't have the power. That scenario places the risk on 21 the developer. 22 If as a result of shifting the SAR methodology 23 to gas-fired and if along with that the utilities in the 24 region, as they seem to be indicating they want to do, all 25 move toward gas-fired resources, then what they're doing is 317 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 reducing their capital exposure and increasing the fuel 2 price exposure, and the discussion on Page 5 basically 3 premises that the utility's shareholders or the developer, 4 whichever, whoever owns the resource, bears most of the risk 5 for the capital exposure, but that the ratepayer bears the 6 risk for the fuel price; so that to make that shift shifts 7 risks from the utility and its shareholders to the 8 ratepayer. 9 Q All right, thank you, Doctor. The '91 10 Northwest Power plan is not an exhibit in the record in this 11 case, is it? That's my understanding. 12 A Not to my knowledge in this case, no. 13 Q On Page 6 of your rebuttal testimony, you 14 indicate that the plan, you infer that there is far too much 15 price and availability risk with natural gas to depend on 16 those resources for base load. Do you have a specific 17 reference to a page? I mean, is this an actual conclusion 18 of theirs or is it your summary of the plan? 19 A Can you tell me which line you're looking at, 20 Mr. Woodbury? 21 Q Yes, Page 6, Lines 10 through 12. 22 A On that page, Lines 19 through 28, I quote a 23 portion of the Council's action plan, not their portfolio 24 discussion, but the action plan, I believe, which comes from 25 Page 38 of the plan. 318 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 Q So you're summarizing the quoted language up 2 above, then? 3 A Well, the language up above -- 4 Q That's the language that you're drawing from 5 the quoted language? 6 A The language up above I'm sure does also draw 7 on discussion found earlier in the document. 8 Q Are you familiar with Idaho Power Company's 9 existing resource stack and as to whether it includes any 10 combustion turbines or combined cycle combustion turbines? 11 A If we can go back to the exhibit you 12 referenced earlier. 13 Q Seven? Are any of those resources existing 14 resources? 15 A Existing resources? 16 Q Yes. They are not in their stack at this 17 time; is that correct? 18 A Oh, in the existing stack, combined cycle 19 turbine, no, they do not, to my knowledge. 20 Q Do you know whether there is in the power 21 plans of the Northwest Power plan they talked about perhaps 22 a percentage of total resources which should be no more, I 23 guess, for combined cycle in order to have a good mix for 24 the Company? Do you understand my question? 25 A Let me take a stab at it and you tell me if 319 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 I'm wrong. I do not remember company specific discussion in 2 the plan. There may be some discussion of investor-owned 3 utilities versus public and I don't remember exactly what 4 that language is, but I do recall it referencing what they 5 expected utilities to do more than what they recommended 6 they do. 7 In the overall stack, as I mentioned, there 8 are two items, there are two items in the stack that are 9 combined cycle CTs totaling 3,000 megawatts and they appear 10 in about the middle of the stack. 11 Q Okay, I don't know that that was the answer to 12 my question. My question was, let's say Idaho Power had a 13 combined cycle combustion turbine in its resource stack, it 14 has a lot of thermal, it has a lot of hydro. Given the risk 15 that the Northwest Power plan planners, I guess, see in fuel 16 over the future, would you say in order for the Company to 17 have a reliable resource stack that the percent of 18 combustion turbine generation, combined cycle combustion 19 turbine generation, shouldn't exceed such a percent of its 20 total resources? 21 A Such a recommendation would be possible, but 22 I'm not going to indicate that I've done quantitative work 23 on what it would be. 24 MR. WOODBURY: Mr. Chairman, thank you, 25 Mr. Slaughter, I have no further questions. 320 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 COMMISSIONER MILLER: Mr. Kline. 2 MR. KLINE: Thank you. 3 4 CROSS-EXAMINATION 5 6 BY MR. KLINE: 7 Q Please turn to Page 11 of your direct 8 testimony. I'm sorry, Page 10. On Page 10 and going on 9 over to Page 11, you discuss the fact that Idaho Power has a 10 number of short-term firm surplus sales agreements that are 11 presently in place; is that correct, Dr. Slaughter? 12 A Yes. 13 Q I'm not really sure exactly what you are 14 recommending in this part of your testimony regarding those 15 short-term surplus sales, Dr. Slaughter. Is it your 16 recommendation that Idaho Power plan to acquire resources to 17 serve the needs of those surplus sales? 18 A Mr. Kline, I'm not sure that I am, that I have 19 a recommendation at this time with regard to the surplus 20 sales and I wasn't intending to be making a recommendation. 21 What I was intending to do is to say that this is something 22 that should be looked at closely, No. 1, because it's not 23 just automatic that the loads go away because the contracts 24 end. Someone I anticipate is going to have to pick up those 25 loads and that comes out of the region's resources; and, 321 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 secondly, I do note language in prior orders that indicate 2 that this is an issue that has come up before the 3 Commission, that the Company and the Commission have 4 discussed this issue and agreed to defer a change until the 5 next biennial review, which I am presuming is to be found in 6 the case that was filed last week, and so it would be 7 appropriate at that time rather than at this time; so my 8 recommendation, then, would be that for purposes of this 9 case they not be removed. 10 Q All right, let me ask you a question, then: 11 Assume that the Commission has accepted your recommendation 12 and also assume that Idaho Power's load forecast has turned 13 out to be correct, what will be the effect on ratepayers if 14 that recommendation has been followed? 15 A Are we talking about the load forecast based 16 in the 1992 economic forecast? 17 Q That's correct. Idaho Power correctly 18 predicted the amount of loads that it would have and based 19 on your recommendation, it did not allow those surplus sales 20 contracts to expire, in fact, acquired resources to cover 21 them, what would be the result as far as ratepayers are 22 concerned if that were to occur? 23 A Okay, the effect if those assumptions were to 24 hold and that were to occur and the Company would wind up 25 paying firm rates for some, for acquisition of some power 322 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 that it then turned around and sold at lower rates, the 2 ratepayer would be paying the differential. 3 Contrary-wise, if the assumptions were that 4 the Company under-forecast growth and/or that the surplus in 5 the region totally disappeared, then the ratepayer would 6 have power at a predetermined price and not have to go out 7 into a deficit kind of market to acquire that power; so much 8 of the points that I'm trying to make in my testimony is 9 that there is risk on both sides. The risk that the Company 10 posits is a real risk. I'm not sure that it's been really 11 quantified very much, but it is a real risk, but there is a 12 risk on the other side of the question. 13 Q Do you think there's been quantification of 14 the likelihood of the high load forecast scenario occurring? 15 A Quantification of the likelihood of the high 16 load forecast. Well, I know that the analysis run by the 17 Company a year ago estimated that the high load, the 18 Company's high load, probability was .08 and that the medium 19 high load probability was .22. I note a couple of things in 20 reference to that: One is that with regard to forecasts 21 made over the last several years by the Power Planning 22 Council and BPA, for example, that the actual experience has 23 been tracking the high forecast rather than the medium 24 forecast, and, secondly, that the 1993 Idaho Power economic 25 forecast for its service territory, in the '93 forecast, the 323 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 estimates of household and employment growth have risen 2 about 25 percent; so my quick judgment would be that from 3 the Company's forecast a year ago to this point anyway that 4 it's the high scenario that's being substantiated. 5 Q All right, you have talked an awful lot about 6 the regional load forecast and I think in your rebuttal 7 testimony you even talked about an impending regional 8 deficit. Let me see if I can find that. Page 4, Line 15, 9 and you quote, again, the Northwest Power plan on Line 26 10 saying that the region is going to need an additional 2,000 11 megawatts by the turn of the century. Isn't the need for 12 that 2,000 megawatts of capacity based on critical water 13 conditions; in other words, in the critical water year, 14 another 2,000 megawatts will be needed? 15 A My expectation is that the Council's language 16 was drafted in the context of the existing planning criteria 17 of all of the utilities in the region; so that, for example, 18 for Idaho Power, I would expect that's what's in there is 19 median water and for most of the other utilities critical 20 water. 21 Q Is there anything in that plan that you can 22 cite to that demonstrates that they have different planning 23 criterias for different utilities in the region; is that 24 your assumption? 25 A I said my assumption, and this is that the 324 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 language was drafted in the context of the existing criteria 2 for the various companies, that the Council did not in fact 3 change the criteria for Idaho Power in drafting the 4 document. 5 Q Okay. Well, let's, if you would, assume for 6 me that the regional plan does in fact use the critical 7 water planning criteria in establishing its need for 8 resources. Can you make that assumption? 9 A Okay. 10 Q I think you should. 11 MR. ORNDORFF: Object. 12 Q BY MR. KLINE: If that's the case, then in a 13 non-critical water year is there going to be resources, 14 energy resources, available that exceed the regional loads 15 in a non-critical water year? 16 A I'm sorry, Mr. Kline, what part of that is the 17 question? 18 Q All right, isn't it true assuming critical 19 water planning criteria that in non-critical water years 20 there will be available capacity in the region that exceeds 21 regional loads? 22 A I would say that it is true that in a 23 non-critical water year there will be capacity in the region 24 that exceeds that that would be assumed under critical 25 water, yes. 325 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 Q Isn't it also true, then, that non-firm 2 surplus energy will be available to Idaho Power in all but 3 not critical water years, again assuming the region is 4 planning on critical? 5 A The statement in the testimony is a quote from 6 the Power Planning Council foreseeing a regional deficit. 7 The question that you ask, as I understand it, is Idaho 8 Power's load/resource balance and that would include, for 9 example, the calculation of Appendix A as we have previously 10 discussed, which I assume is calculated under assumptions of 11 median water. My problem with the question is that I'm 12 not -- it's difficult for me to formulate an answer. 13 Q What I'm really asking you to do, you in your 14 testimony have painted a picture of regional deficit and 15 what I'm trying to do is make sure that we have a proper 16 understanding of how that regional deficit would compare to 17 an Idaho Power deficit; so that's what I'm trying to do. 18 MR. ORNDORFF: Mr. Chairman, I object to the 19 line of questioning. Mr. Slaughter has offered no testimony 20 as to how Idaho Power's critical water year relates to the 21 regional forecast. He's offered testimony on the regional 22 forecast and to start drawing hypotheticals and asking the 23 witness questions upon which he has not presented any 24 testimony or prepared or done any analysis is just not 25 productive. 326 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 MR. KLINE: There's a couple of responses I'd 2 like to make to that. First of all, he's the one that's 3 placed into the record the testimony regarding the Northwest 4 Power plan and the deficits that are quoted in that Power 5 plan. He has also consistently through his testimony 6 testified that there is great risk that if we don't have 7 enough resources there's going to be all kinds of problems 8 if we don't acquire additional resources, and what I'm 9 saying is we need to look at Idaho Power's specific 10 situation, compare it to the regional deficits that he has 11 quoted, I think that's fair cross-examination. 12 MR. ORNDORFF: I'd reply, Mr. Chairman, that 13 if the Company wants to introduce that testimony they should 14 elicit from their own witness that testimony. 15 MR. KLINE: He's the one that -- 16 COMMISSIONER MILLER: I'm prepared to rule. 17 It does seem to me that the question of whether regional 18 forecasts are truly applicable to the Idaho circumstance or 19 not is a fair line of inquiry to the extent this witness 20 knows about that. It seems to me to be a fair thing to look 21 into, and it does, obviously, seem relevant to the general 22 theme of the testimony; so my inclination is to allow this 23 line of cross-examination. 24 Q BY MR. KLINE: Again, assuming that the region 25 plans on critical water, an assumption you've made, and 327 CSB REPORTING SLAUGHTER (X) Wilder, Idaho 83676 Rosebud 1 Idaho Power plans on median water, if the region constructs 2 resources based on critical water planning, doesn't that, 3 per se, mean that in non-critical water years resources are 4 going to be available that Idaho Power would have access to? 5 A In the way in which you state the question 6 this time, yes. 7 MR. KLINE: That completes my 8 cross-examination. 9 COMMISSIONER MILLER: Do you have any 10 questions? 11 COMMISSIONER NELSON: I have no questions. 12 COMMISSIONER MILLER: Do you have questions? 13 COMMISSIONER SMITH: Yes. 14 15 EXAMINATION 16 17 BY COMMISSIONER SMITH: 18 Q I thought for sure someone else would ask it, 19 but since they didn't, I'm finding in your rebuttal on 20 Page 6 a sentence that starts on Line 1, it seems to imply 21 that this project which will burn coal or waste coke is 22 somehow a renewable project. Was that your intention? 23 A Yes, it was. That's my understanding of the 24 regulations and that is also the thrust of conversations 25 I've had with Staff, that the -- 328 CSB REPORTING SLAUGHTER (Com) Wilder, Idaho 83676 Rosebud 1 Q Coal is a renewable resource? 2 A Let me expand here. This sentence is in the 3 context of petroleum coke and waste coal. Now, there was 4 some discussion this morning, some questions anyway, about 5 the ability of the plant to burn coal, run-of-the-mine coal, 6 but it's my recollection that Mr. Blendu said that, yes, it 7 could burn it, but what is intended to burn is waste and 8 petroleum coke. 9 Q In what sense are those renewable? 10 A Petroleum coke is a by-product of oil 11 refining. 12 Q Right, and now is oil renewable? 13 A Oil is not renewable, but the coke has no 14 alternative use. The oil company, the refinery, has to pay 15 to dispose of it somewhere; so in that sense you're using a 16 resource that has no other productive use at this time. 17 Q So that's the sense in which you mean 18 renewable? 19 A Yes. 20 Q It's not like wind or sun? 21 A Not like solar, no, but in the sense that 22 there is a waste product here that can be disposed of in 23 this particular fashion. 24 Q When the underlying product is gone, the waste 25 product isn't there either. 329 CSB REPORTING SLAUGHTER (Com) Wilder, Idaho 83676 Rosebud 1 A At such time as that occurs, that would be 2 correct. 3 Q So in that sense it's not renewable. 4 A That is true, but that's well beyond the 5 lifetime of this plant. 6 Q You think natural gas is going to run out in 7 the lifetime of this plant? 8 A No, I don't. 9 Q I guess my other question because I'm not 10 familiar with it is on Exhibits 11 and 12, they're from Data 11 Resources, Inc., and I'm not familiar with that group. 12 Could you tell me what their background or association is? 13 A There are two large economic forecasting firms 14 in the United States. There have been, oh, there's been at 15 least one more in the past at various times, Evans 16 Economics, but those two are Data Resources, Inc., based in 17 Lexington, Massachusetts, and the WEFA Group, the Wharton 18 Economic Forecasting Associates, which was originally 19 associated and may still be associated, Mr. Church can 20 answer the question, with the University of Pennsylvania, 21 the graduate school. 22 Data Resources, I don't remember which one 23 first started making economic forecasts. The State of Idaho 24 first contracted with Data Resources for long-term and 25 short-term national macroeconomic forecasts in 1978. 330 CSB REPORTING SLAUGHTER (Com) Wilder, Idaho 83676 Rosebud 1 Q So they're not affiliated with any industry or 2 group, they're just an independent forecaster? 3 A They are independent, yes. 4 COMMISSIONER SMITH: Thank you, Mr. Chairman. 5 I think those are all my questions. 6 COMMISSIONER MILLER: Redirect. 7 MR. ORNDORFF: Mr. Chairman, I have no 8 questions. 9 COMMISSIONER MILLER: Dr. Slaughter, thank you 10 once again for your help. 11 THE WITNESS: Thank you. 12 COMMISSIONER MILLER: Can this witness be 13 excused if he desires? 14 MR. KLINE: No objection. 15 COMMISSIONER MILLER: You're free to come and 16 go as you wish. 17 (The witness left the stand.) 18 MR. ORNDORFF: Should we proceed on? 19 COMMISSIONER MILLER: Let's do. 20 MR. ORNDORFF: I'd like to call Dr. Don 21 Reading as the next witness for Rosebud. 22 23 24 25 331 CSB REPORTING SLAUGHTER (Com) Wilder, Idaho 83676 Rosebud 1 DON C. READING, 2 produced as a rebuttal witness at the instance of Rosebud 3 Enterprises, Inc., having been first duly sworn, was 4 examined and testified as follows: 5 6 DIRECT EXAMINATION 7 8 BY MR. ORNDORFF: 9 Q Would you give us your full name and business 10 address? 11 A Don C. Reading, 1311 North 18th, Boise, Idaho. 12 Q Are you the same Don C. Reading that caused to 13 be filed in this case certain prefiled testimony? 14 A Yes. 15 Q Are you sponsoring any exhibits? 16 A Yes. 17 Q Do you have any changes to those exhibits? 18 A Yes. 19 Q Would you lead us through that? 20 A If you look at my testimony on Page 7, I have 21 a quote and reference Exhibit 1. In my exhibit, there were 22 two pages. The quote in there is not on any of those 23 pages. On Page 6, I also discuss down at the bottom, 24 Lines 19, 20, and 21, some percents different than -- 25 MR. KLINE: Wait a minute, I'm not keeping up, 332 CSB REPORTING READING (Di-Reb) Wilder, Idaho 83676 Rosebud 1 Don. 2 THE WITNESS: Oh, okay, sure. 3 MR. RIPLEY: Could you start all over again? 4 THE WITNESS: Sure. At the top of Page 7, 5 Line 2, I reference Exhibit 1. The implication is one can 6 find that quote in Exhibit 1. 7 MR. KLINE: What Exhibit 1? 8 MR. RIPLEY: Could we go off the record? I 9 don't think we need to do all this on the record, 10 Mr. Chairman. 11 COMMISSIONER MILLER: There does appear to be 12 some confusion here. We can go off the record for a 13 second. 14 (Off the record discussion.) 15 (Recess.) 16 COMMISSIONER MILLER: We'll go back on the 17 record now after our recess and Dr. Reading will explain the 18 misunderstanding that has arisen with respect to his 19 prefiled testimony. 20 THE WITNESS: On the top of Page 7, at the end 21 of a quote it says, "Exhibit 1." That implies that one can 22 find that quote in Exhibit 1. As was pointed out before we 23 went off the record, that should really say, "Exhibit 10." 24 In Exhibit 10, there are two pages. Those two pages do not 25 contain the quote. The two pages, one of the two pages that 333 CSB REPORTING READING (Di-Reb) Wilder, Idaho 83676 Rosebud 1 I handed out does contain that quote. 2 MR. KLINE: Which one? 3 THE WITNESS: The one that says "5 of 6" in 4 the lower right-hand corner. This is a copy of an exhibit 5 that Idaho Power had attached to one of their witnesses' 6 testimony in an earlier hearing. 7 COMMISSIONER MILLER: For the purpose of 8 clarity, then, Exhibit 10 should be supplemented to include 9 the two pages that you have now handed out and Exhibit 10 10 now becomes a four-page exhibit. 11 THE WITNESS: Correct. That is all the 12 changes I have. 13 Q BY MR. ORNDORFF: Dr. Reading, if I were to 14 ask you the questions with the changes that you just went 15 through, would you have any different answer today? 16 A No, I would not. 17 MR. ORNDORFF: With that, Mr. Chairman, I 18 would like to spread Dr. Reading's testimony on the record 19 and tender him for cross-examination. 20 COMMISSIONER MILLER: If there is no 21 objection, Exhibit No. 10 will be marked and the direct 22 prefiled testimony of Dr. Reading will be spread on the 23 record as if read in full. 24 (The following prefiled testimony of Dr. Don 25 Reading is spread upon the record.) 334 CSB REPORTING READING (Di-Reb) Wilder, Idaho 83676 Rosebud 1 Q WOULD YOU PLEASE STATE YOUR NAME AND ADDRESS? 2 A Don C. Reading, 1311 No. 18th, Boise, Idaho 3 83702. 4 Q WOULD YOU PLEASE BRIEFLY DESCRIBE YOUR 5 QUALIFICATIONS? 6 A Yes. I am a consulting economist and vice 7 president of Ben Johnson Associates, Inc., a firm of 8 economic and analytic consultants specializing in public 9 utility regulation. I have been actively involved in more 10 than 100 formal regulatory proceedings concerning electric, 11 telephone, natural gas, and water utilities. 12 I have provided expert testimony on more than 75 13 occasions in proceedings before state courts, federal 14 courts, and regulatory commissions. I have presented or 15 have pending expert testimony or reports before regulatory 16 commissions in 15 states and the District of Columbia as 17 well as before the Interstate Commerce Commission and the 18 Federal Communications Commission. 19 Q HAVE YOU PREPARED AN APPENDIX WHICH DESCRIBES 20 YOUR QUALIFICATIONS IN REGULATORY AND UTILITY ECONOMICS IN 21 GREATER DETAIL? 22 A Yes. I have prepared Appendix I for this 23 purpose. 24 Q DR. READING, HAVE YOU REVIEWED IDAHO POWER'S 25 1993 INTEGRATED RESOURCE PLAN (IRP) AND RELATED TESTIMONY 335 1 FILED IN THIS DOCKET? 2 A Yes. I have. 3 Q WOULD YOU PLEASE DISCUSS YOUR UNDERSTANDING OF 4 IDAHO 5 6 / 7 8 / 9 10 / 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 336 1 POWER'S CONTRACTUAL USE OF ITS IRP REGARDING QF PROJECTS 2 LARGER THAN 10 MW? 3 A Yes. There are two distinct issues involved 4 in such contract negotiations. The first is the validity, 5 given the Commission's orders, of using the IRP rather than 6 the Surrogate Avoidable Resource (SAR) as a starting point 7 for negotiating rates. The second issue is the validity of 8 the methods, parameters, and values that are embedded in the 9 Company's IRP calculations. 10 Q WOULD YOU ADDRESS THE FIRST ISSUE--THE USE OF 11 IPCO's IRP RATHER THAN THE COMMISSION-APPROVED SAR AS A BASE 12 FOR ESTABLISHING QF RATES FOR PROJECTS OVER 10 MW IN SIZE? 13 A Yes. The Company's preference seems to have 14 the following source. First, according to IPCo, the 15 Commission has sharply distinguished QFs of 10 MW and larger 16 from those below 10 MW. According to the Company, this is 17 because such larger projects have a potential impact on the 18 "planning, operating, and revenue requirement" of the 19 Company. [Direct Testimony of Jan B. Packwood, p. 2.] 20 Therefore, the Company claims, 21 Because the IRP explicitly sets forth Idaho Power's 22 future need for resources and the selection and type of 23 resources the Company expects to acquire under least 24 cost planning, the IRP provides the most appropriate 25 basis for the determination of the costs Idaho Power 337 1 can avoid by acquiring a particular project. [Direct 2 Testimony of John Wilmorth, p. 3] 3 According to the Company's logic, since QF projects upward 4 of 10 MW have been placed by the 5 6 / 7 8 / 9 10 / 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 338 1 Commission in a different category from smaller projects, 2 and since the reasons for the Commission's demarcation are 3 embodied in IPCo's IRP, the use of the IRP is within the 4 "ground rules" established by the Commission. 5 Q DO YOU AGREE WITH THE COMPANY'S CONCLUSION 6 THAT THE USE OF THEIR IRP IS WITHIN THE "GROUND RULES" SET 7 FORTH BY THE IDAHO COMMISSION? 8 A No. As pointed out in the direct testimony of 9 both Dr. Slaughter and Staff witness Faull, the Commission 10 has been clear in the use of the SAR to establish avoided 11 cost rates as a starting point for negotiating rates for QF 12 projects larger than 10 MW. I need not repeat their 13 discussions here. In addition, the Commission stated in 14 Order No. 22636 that 15 We find no avoided cost methodology presented in this 16 case that is pragmatically superior to the existing 17 surrogate avoidable resource (SAR)... Furthermore, we 18 find that the most appropriate surrogate resource for 19 determining avoidable long term cost of utilities 20 operating in Idaho is a single hypothetical coal-fired 21 steam plant with state of the art emission controls. 22 [Idaho Public Commission Order No. 22636, pp. 67-68.] 23 Clearly, the Commission did NOT say that a utility's 24 planning process was the "pragmatically superior" method for 25 determining avoided cost rates, as Idaho Power claims. 339 1 Q BUT THE COMMISSION ALSO FOUND THAT THE 2 PLANNING PROCESS 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 340 1 SHOULD CONSIDER A UTILITY'S LOAD-RESOURCE BALANCE. WOULDN'T 2 THAT PART OF THE COMMISSION'S ORDER TEND TO SUPPORT THE 3 COMPANY'S POSITION? 4 A No. In this regard the Commission said as 5 follows: 6 Nor do we find a method for determining the established 7 time of load-resource balance that is superior to using 8 each specific utility's most recent load-resource plan 9 (as incorporated in its Resource Management Report) as 10 the basis for a Commission determination establishing 11 surrogate utility specific resource plans following 12 public hearing. [Ibid., p. 67, 68] 13 Published avoided cost rates do include the utilities 14 load-resource balance because the rates are discounted from 15 the year the utility expects to be in deficit. This is very 16 different from using a company's resource plan, with all its 17 embedded assumptions, as the basis for determining QF rates. 18 Q WHAT IS YOUR RECOMMENDATION REGARDING THIS 19 ISSUE? 20 A In my opinion, the Commission's orders give 21 clear guidance regarding the establishing of rates for QFs 22 larger than 10 MW. These orders plainly state that the 23 basis for negotiated rates will be the published avoided 24 cost rates based on the SAR. Using IPCo's Integrated 25 Resource Plan does not fit within the "ground rules" 341 1 established by the Commission. I therefore recommend that 2 the Commission reject the Company's contention and direct 3 IPCo to use the SAR in negotiating rates for the larger QFs. 4 5 / 6 7 / 8 9 / 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 342 1 Q WHAT IF THE COMMISSION DECIDES IN THE 2 COMPANY'S FAVOR ON THIS ISSUE? 3 A The Commission is, of course, the ultimate 4 arbitrator of what it does and does not mean, and it might 5 decide that the IPCo's IRP is in fact the appropriate 6 starting point, rather than the litigated SAR. However, if 7 it does, the Commission needs to be prepared to reconcile 8 various conflicts between the IPCo's IRP and established 9 Commission policy. Perhaps more importantly, the Commission 10 will need to grapple with numerous items contained in IPCo's 11 IRP that can significantly impact avoided cost rates. These 12 items have not been previously evaluated through the public 13 hearing process or ruled on by the Commission. 14 Q YOU ARE NOW DISCUSSING THE SECOND ISSUE--THE 15 VALIDITY OF THE METHODS, PARAMETERS, AND VALUES USED IN THE 16 CALCULATIONS EMBODIED IN THE COMPANY'S IRP. WOULD YOU 17 DISCUSS SOME EXAMPLES TO ILLUSTRATE YOUR POINT? 18 A Certainly. I realize, of course that this is 19 not a hearing on the reasonableness of IPCo's IRP. However, 20 because the Company is using its IRP to generate rates 21 offered to Rosebud, the appropriateness of this approach is 22 relevant. The following examples raise questions about the 23 appropriateness of using the current IRP to establish rates 24 for Qfs of 10 MW and more. My intent is to show how the 25 assumptions and values used by Idaho Power are either 343 1 outside established Commission policy or have not been 2 exposed to the public hearing process--at least, not 3 sufficiently to legitimize their use in establishing QF 4 rates. In describing how each factor is used in the 5 calculation of avoided costs, I am not claiming to have made 6 a full-blown 7 8 / 9 10 / 11 12 / 13 14 15 16 17 18 19 20 21 22 23 24 25 344 1 analysis or investigation of the IRP. I simply wish to 2 indicate to the Commission how each factor impacts the rates 3 offered by the Company to Rosebud. 4 Q WHAT IS YOUR FIRST EXAMPLE OF INAPPROPRIATE 5 ELEMENTS USED IN DEVELOPING RATES UNDER THE COMPANY'S IRP? 6 A According to the Company, the rates developed 7 and offered to Rosebud have a 2.5 mill per Kwh first-year 8 adjustment for "[t]he cost associated with rebalancing Idaho 9 Power's capital structure to account for the imputed 10 debt..." [Direct Testimony of John Wilmorth, p. 12.] 11 The method for finding this kind of adjustment was 12 developed by Standard & Poor's (S&P). S&P uses it to 13 measure the impact on a utility's cost of capital of 14 significant long-term fixed power purchase contracts. 15 I have two problems with the use of this adjustment. 16 First, to the best of my knowledge, the Commission has not 17 ruled on the validity of such an adjustment or the 18 methodology used to calculate it. The Commission has not 19 approved it for arriving at a utility's overall rate of 20 return, or for its incorporation as an element in 21 establishing avoided cost rates. This alone rules it out as 22 a proper adjustment for Idaho Power to make. 23 Second, the Company appears to misapply the S&P 24 method, which the rating agency reserves for utilities with 25 large percentages of their total loads supplied by purchase 345 1 power contracts. Standard & Poor's notes that "as a 2 practical matter, overall purchased power risk is usually 3 not significant until purchased power exceeds 10%-15% of 4 capacity." [IPCo, Hoyd Direct Testimony, Case No. GNR-E-93-6 5 Exhibit 2; See Exhibit 1, attached]. 6 Q HOW LARGE A PART OF IPCO'S LOAD IS SUPPLIED BY 7 PURCHASED POWER NOW? 8 A According to the Company's IRP, 1993's 9 expected average total load will be 10 11 / 12 13 / 14 15 / 16 17 18 19 20 21 22 23 24 25 346 1 1,660 average MW. [Idaho Power, Integrated Resource Plan, 2 Technical Appendix, March 10993, p. 10.] In the first 3 Quarter of 1993 there were 57 QFs selling power to IPCo with 4 an average of 64 MW and capacity of 115.4 MW. [Idaho Power, 5 Acquisition of Supply-Side Resources, Sept. 1993, p. 8.] 6 This means that less than 4% of the Company's load is 7 currently supplied by QFs. (A recent Commission Order uses 8 1992 long-term purchase power contracts for Idaho Power at 9 4% of total generation. [Idaho Public Utilities Commission, 10 Order No. 25218, p. 6]) 11 Through 1996, existing and committed QF resources are 12 expected by the Company to have an average annual output of 13 160.7 MW. [Idaho Power, Integrated Resource Plan, March 14 1993, p. 14.] The 1996 average MW load is forecast at 1.727 15 MW. [Ibid., Sales and Load Forecast, p. 29.] Therefore, by 16 1996 QFs are expected to be about 9.3% of the Company's 17 load. This is still below the level that Standard and 18 Poor's sees as having any practical significance on a 19 utility's rate of return. 20 Q HOW DID THE COMPANY CALCULATE THE ADJUSTMENT 21 AS APPLIED TO THE RATES OFFERED TO ROSEBUD? 22 A I have not examined the Company's workpapers. 23 But according to Standard & Poor's, the first step in their 24 process is to make a "qualitative evaluation" of the risk 25 factor. S&P deemed that its risk factors vary according to 347 1 whether the purchase is from a non-capitalized 2 sale/leaseback (70%-100%), a take-or-pay contract (40%-80%), 3 or a take-and-pay contract (0%-50%). Then 4 [t]he procedure to adjust debt would be to take the net 5 present value of future capacity payments discounted at 6 10%. The 10% discount factor was chosen to approximate 7 a utility's average cost of capital. The result -the 8 potential debt 9 10 / 11 12 / 13 14 / 15 16 17 18 19 20 21 22 23 24 25 348 1 equivalent - would be multiplied by the risk factor. 2 That result would be added to the utility's reported 3 debt. [Exhibit 10.] 4 According to Dr. Wilmorth, the Company apparently uses 5 the above procedure and then translated the results into an 6 avoided cost adjustment. My point is that the process is 7 complex, involves a host of judgments, and has not been 8 reviewed by the Commission as appropriate for adjusting 9 avoided cost rates. 10 Given the Commission's current policies, this 11 adjustment appears improper on two grounds: First it has 12 been misapplied; second, S&P's methodology for the 13 calculation of the adjustment is suspect. 14 Q WHAT IS YOUR SECOND EXAMPLE OF AN 15 INAPPROPRIATE ELEMENT IN THE COMPANY'S IRP? 16 A It concerns the treatment of certain 17 "nondeferrable" resources in IPCo's IRP resource stack. 18 According to Company witness John Wilmorth, 19 [t]he Shoshone Falls Expansion is not deferrable beyond 20 2004 if constructed as a condition for the relicensing 21 of the existing Shoshone Falls facility. [IPCo, 22 Wilmorth Direct Testimony p. 11.] 23 He goes on to state that the Company plans to seek 24 additional Commission directives on the project, and 25 [t]he effect of the Shoshone Falls expansion on the avoided cost for the Project is 349 1 limited by the fact that the expansion is planned to 2 occur six years after the proposed start of a contract 3 for the Project. [Ibid., pp. 11-12.] 4 However, in its Action Plan for Acquisition of 5 Supply-Side Resources, the Company advocates foregoing the 6 relicense upgrades of Shoshone Falls and Upper Salmon Falls, 7 contingent on regulatory or licensing requirements. I am 8 not debating whether or not FERC will require IPCo to 9 upgrade Shoshone Falls as a condition of its relicense. The 10 point I am making is the questionable status of 11 "nondeferrable" resources in the Company's IRP resource 12 stack. In addition, the Company claims that the impact on 13 avoided costs of maintaining the Shoshone Falls upgrade in 14 the portfolio is "limited." Of course, anything that is not 15 limitless is limited. Without a full disclosure of the IRP 16 process and its ramifications through the hearing process, 17 the real extent of a "limited" impact remains a mystery. 18 Q HAVE YOU REVIEWED THE SUPPLY-SIDE RESOURCE 19 PORTFOLIO CONTAINED WITHIN THE COMPANY'S IRP? 20 A No. Time constraints have prevented me from 21 undertaking a thorough investigation of the Company's 22 supply-side resource portfolio. However, my review of the 23 estimates of the costs of the resources in the IRP indicates 24 to me that further investigation is warranted. According to 25 the IRP, on a 30-year nominal levelized basis, costs vary 350 1 between 37.0 and 86.6 mills per kWh. [IPCo, Integrated 2 Resource Plan Technical Appendix, March 1993, pp. 114-116.] 3 The highest cost is for a gasified coal unit, the lowest for 4 the Wiley project. It surprises me that a concrete facility 5 can be built across the Snake River for a cost of 37.0 6 mills. It is also surprising that the Company, given the 7 low cost of this resource, is 8 ... proposing to the Idaho Commission that the Company 9 abandon the 10 11 / 12 13 / 14 15 / 16 17 18 19 20 21 22 23 24 25 351 1 development of the Wiley project for both economic and 2 environmental reasons with the expectation that, for 3 the same reasons, the project will not be developed by 4 other interests [Acquisition of Supply-Side Resources, 5 Sept. 1993, p. 24] 6 Again, as above, I have not explored the validity of 7 this cost estimate or the desire of the Company to withdraw 8 the project from future consideration. What I am saying is 9 that the costs appear to be at odds with other estimates of 10 similar resources. However, for the calculation of rates 11 offered Rosebud, the Wiley project remains part of the 12 resource stack used in the IRP and thus may have an impact 13 on the avoided costs that this process produces. 14 Q ARE THERE ANY OTHER EXAMPLES YOU WOULD LIKE TO 15 DISCUSS? 16 A Yes. Dr. Slaughter discusses in his Direct 17 Testimony the fact that the Commission was plain about the 18 "circuitous process" of using QF/conservation resources in 19 the determination of avoided cost rates. [Direct Testimony 20 of Richard Slaughter, pp. 9-10.] Conservation, however, 21 remains part of the resources in the calculation of the 22 avoided cost rates offered to Rosebud. 23 This is another example of the Company's use of its 24 IRP process that is at odds with the procedures established 25 by the Commission. Only a full hearing, with the 352 1 participation of all affected parties and a subsequent 2 Commission ruling, can resolve these issues. The Company's 3 unilateral approach does not meet the Commission's 4 established precedent. 5 Q BOTH IDAHO POWER AND PACIFICORP WITNESSES 6 DISCUSS THE VALUE OF USING WHAT THEY CALL A "MARKET-BASED 7 APPROACH" TO DETERMINE THE NEED FOR QF RESOURCES AND PRICES. 8 DO YOU WISH TO 9 10 / 11 12 / 13 14 / 15 16 17 18 19 20 21 22 23 24 25 353 1 COMMENT ON THEIR POSITION? 2 A Yes, because I consider it deeply flawed. 3 Typical of their approach is an analysis in IPCo's position 4 paper, which supposedly shows how much more it costs to 5 purchase from QFs than to rely on the Company's resources, 6 based on "Historical Costs Above Market" (Figure 3) and 7 "Prospective Costs Above Market" (Figure 6). [Acquisition 8 of Supply Side Resources, pp. 11-17.] 9 The market price used in this discussion is based on 10 spot energy prices and capacity prices. The problem with 11 this analysis is two-fold. First, it uses spot or market 12 power in long-term resource planning, and the Company's 13 implicit definition of "the market" thus does not accord 14 with general usage of that term and biases the entire 15 argument in IPCo's favor. Second, when making the 16 comparison of resource costs, the Company uses total QF 17 costs but its own variable costs--an apples and oranges 18 comparison. 19 Q WOULD YOU EXPAND ON YOUR FIRST POINT--THE 20 COMPANY'S ERROR IN USING SPOT PRICES IN THE CONTEXT OF 21 LONG-TERM PLANNING? 22 A Yes. In the first place, there's a problem 23 with IPCo's and PacifiCorp's notion of what constitutes "the 24 market." IPCo indicates that for most of the past 10 years 25 spot energy was available for 25 mills per kWh or less 354 1 (unsurprising in a time of regional surplus and nonfirm 2 power). But as the Commission knows, the cost of long-term 3 firm purchases and the cost to ratepayers for the Company's 4 own baseload facilities is significantly above this figure. 5 The reason for this higher cost is well known: There is 6 real value, to both the Company and consumers, in having 7 assured power availability at a known price. This is 8 precisely why the "market" rates for long-term and spot 9 power diverge. 10 11 / 12 13 / 14 15 / 16 17 18 19 20 21 22 23 24 25 355 1 However, the Company implies that it may now be proper 2 to plan on the assumption that nonfirm power will always be 3 available. 4 Non-firm energy has been available in the wholesale 5 market virtually around the clock over the last decade. 6 The availability of non-firm energy is anticipated to 7 continue in the future. [Ibid., p. 26.] 8 This would seem to obliterate the difference between 9 spot prices and long-term prices. But this inference is 10 contradicted the Company's current Integrated Resource Plan: 11 However, with the disappearance of the regional resource 12 surplus and increasing restrictions on hydropower 13 operations to meet non-power requirements, the 14 continuation of hydro capacity surpluses can on longer 15 be assumed. [Idaho Power, Integrated Resource Plan, 16 March 1993, p. 34.] 17 Dr. Slaughter also testifies that the region has now 18 depleted its generating surplus and needs to acquire 19 additional resources. As someone who first testified 15 20 years ago in this hearing room, I find the turnaround in the 21 Company's approach to be astounding. 22 My first testimony was in a hearing for a certificate 23 for the Pioneer Plant. At that time the Company was 24 forecasting something like 6-7 percent compound growth in 25 load over the next 20 years, and a Company executive was 356 1 handing out "Let the Bastards Freeze in the Dark" bumper 2 stickers. The assumption was there was a growing demand for 3 the power and the best way for a consumer to get it was to 4 lock in to long-term Company resources before the price of 5 new resources went up. The fact the Company's resources 6 were large and there would be temporary surpluses was said 7 to be a small price to pay for an assured supply at a fixed 8 price. Now the Company seems to be saying something else: 9 10 / 11 12 / 13 14 / 15 16 17 18 19 20 21 22 23 24 25 357 1 The burden on ratepayers would be the cost of large 2 amounts of excess capacity persisting over a long 3 period, perhaps as long as a decade. [Direct Testimony 4 of Thomas W. Parkinson, p. 11.] 5 Ratepayers and Commissioners in the region are well 6 aware of the costs of excess capacity. But now the region's 7 loads have grown and the surplus is gone. As the Company 8 has indicated, the region now needs additional resources to 9 fill consumer demand. 10 A look at the long-term costs of many of Idaho Power's 11 own baseload resources shows they have been a good deal for 12 both ratepayers and the Company. This is because they were 13 built when construction costs were significantly lower than 14 today and rates are locked in at those lower prices. 15 An important policy question before the Commission is 16 the weighing of the tradeoff between the value of 17 longer-term fixed resources with known costs versus shorter 18 term commitments with the risks that future resources may 19 cost significantly more. 20 Q THE COMPANY SAYS THAT BUYING AT MARKET RATES 21 AND FOR THE SHORT RUN WILL ADD VALUABLE FLEXIBILITY TO THE 22 PLANNING PROCESS. DO YOU AGREE? 23 A While I agree that increased flexibility adds 24 value to the planning process, it is only one of many 25 factors that need to be considered. The vast majority of 358 1 power being supplied to IPCo customers is from the Company's 2 baseload resources. These are long term commitments. The 3 type of new resources selected can have varying degrees of 4 risks to ratepayers. 5 For example, the resource stack used by the Company to 6 develop the QF rates 7 8 / 9 10 / 11 12 / 13 14 15 16 17 18 19 20 21 22 23 24 25 359 1 offered to Rosebud contains four combustion turbines (CTs) 2 by the year 2012. Without Rosebud these 80 MW CTs are 3 scheduled on line in 2006, 2008, 2009, and 2011. With 4 Rosebud they are added to the resource stack in 2007, 2008, 5 2010, and 2012. 6 These dates are well in the future, and the Company's 7 resource plan will surely change in the interim. But let's 8 assume that the CTs do become part of the Company's 9 resources as the IRP now suggests. With a CT resource, if 10 either the price of fuel increases more than expected or 11 loads grow more rapidly than expected, then the per-kWh cost 12 of output from that CT would exceed that from a baseload 13 plant, and the Company's power supply costs would go up more 14 than currently anticipated. 15 As the recent drought has shown, the Company is not 16 shy about asking for surcharges to meet increased power 17 supply costs. In this sense then ratepayers are at risk 18 because they will be expected to pay for those increased 19 power supply costs. 20 My point is that anything other than a strict small 21 increment optimal path will not be the least-cost course. 22 There are costs to the system for the inevitable mistakes 23 that will be made. The Company in this filing has presented 24 a case for the risks of adding long-term baseload resources 25 that may not be needed in the short term. What the Company 360 1 hasn't presented are the risks to consumers for not adding 2 baseload long-term resources. 3 Q WOULD YOU NOW EXPLAIN MORE FULLY WHAT YOU SEE 4 AS THE SECOND FLAW IN IPCO'S COMPARISON OF ITS RESOURCE 5 COSTS TO MARKET PRICES? 6 A Yes. Apparently when comparing resource costs 7 that are above spot market rates the Company is using total 8 QF costs compared with the Company's resources at variable 9 costs only. The flaw in this approach is, of course, that 10 QF costs in rates include capital, fuel, and 11 12 / 13 14 / 15 16 / 17 18 19 20 21 22 23 24 25 361 1 O&M costs, whereas the Company's resources as treated in the 2 same analysis include only variable running costs. [IPCo, 3 Acquisition of Supply-Side Resources, p. 13.] Yet 4 ratepayers are paying the Company all the costs of the 5 Company's resources in their rates not just the variable 6 costs. 7 If the Company wants to make a fair comparison of the 8 impacts of its own and QF resources, it needs to do so in a 9 consistent way and include the capital costs of its own 10 resources in the Company portion of above-market costs. As 11 a ratepayer I would certainly have a different view of the 12 cost of including QF resources in my rates if the Company 13 were to charge me only for the variable costs of its own 14 resources. 15 Q WOULD YOU PLEASE SUMMARIZE YOUR TESTIMONY? 16 A Yes. Idaho Power has used its IRP as the 17 basis for determining rates offered to Rosebud. This 18 approach is at odds with the Commission's orders. In 19 addition, the Company's IRP process involves a host of 20 complex calculations, values, and assumptions that have a 21 significant impact on the determination of avoided costs 22 rates generated by the process. I recommend that the 23 Commission inform the Company that the use of its IRP to 24 determine rates for QFs larger than 10 MW is not consistent 25 with the Commission Orders. I further recommend that the 362 1 Commission direct IPCo to use the SAR as the basis for the 2 calculation of QFs. 3 If the Commission decides to use the company's IRP 4 process for the calculation of QF rates, it should require a 5 hearing on the IRP itself as a replacement for the SAR. 6 Meanwhile, the Commission should direct Idaho Power to use 7 the current SAR rates as a basis for avoided cost rates 8 offered to all QFs. 9 Q DOES THIS CONCLUDE YOUR REBUTTAL TESTIMONY AS OF 10 11 / 12 13 / 14 15 / 16 17 18 19 20 21 22 23 24 25 363 1 DECEMBER 1, 1993? 2 A Yes, it does. 3 4 / 5 6 / 7 8 / 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 364 1 (The following proceedings were had in open 2 hearing.) 3 COMMISSIONER MILLER: Mr. Richardson. 4 MR. RICHARDSON: No questions for this 5 witness, Mr. Chairman. 6 COMMISSIONER MILLER: Mr. Burleigh. 7 MR. BURLEIGH: No questions, Mr. Chairman. 8 COMMISSIONER MILLER: Mr. Fell. 9 MR. FELL: Yes, Mr. Chairman. 10 11 CROSS-EXAMINATION 12 13 BY MR. FELL: 14 Q Dr. Reading, on Page 9 of your testimony -- 15 A Yes. 16 Q -- there's a question that states that both 17 Idaho Power and PacifiCorp witnesses discuss using a 18 market-based approach, and then you go on to talk about the 19 use of spot prices as the market-based test; is that 20 correct? 21 A I use the example of spot prices, yes. 22 Q Is it your understanding that PacifiCorp's 23 market-based standard for determining the avoided cost is 24 based on spot prices? 25 A No. 365 CSB REPORTING READING (X-Reb) Wilder, Idaho 83676 Rosebud 1 Q Would you explain? 2 A Well -- 3 Q Explain your reference to PacifiCorp in this 4 context. 5 A That in the testimony, let's see, I'd have to 6 go look, I think of the PacifiCorp witness, he discusses a 7 market-based approach for determining avoided costs. Then 8 without probably clear demarcation, I then went into a 9 discussion of what Idaho Power presented of a market-based 10 approach and the discussion of spot prices. I was not 11 trying to imply that that was also the position of Pacific 12 Power. I have not investigated the specific proposal of 13 PacifiCorp on a market-based determination of avoided cost 14 rates. 15 MR. FELL: Thank you. No further questions. 16 COMMISSIONER MILLER: Mr. Woodbury. 17 MR. WOODBURY: Thank you, Mr. Chairman. I 18 just have a short question. 19 20 CROSS-EXAMINATION 21 22 BY MR. WOODBURY: 23 Q Mr. Reading, Page 3, Line 18, you make a 24 recommendation that the basis for negotiated rates be the 25 published avoided cost rates based on the SAR, and then on 366 CSB REPORTING READING (X-Reb) Wilder, Idaho 83676 Rosebud 1 Page 14, Line 20, you state that if the Commission decides 2 to use the Company's IRP process for the calculation of QF 3 rates, it should require a hearing on the IRP as a 4 replacement for the SAR. My question is, assuming we did 5 have a hearing as you suggest, if we utilized the Company's 6 integrated resource plan as a basis for avoided cost 7 determination with whatever adjustments are made, what 8 procedures should be followed if the Company wants to change 9 something that affects the rate? 10 A Oh, wow. I'll be the economist with a captive 11 audience. I'll answer it and not really answer it, because 12 the basic answer is I don't have a specific recommendation 13 of how often. One of the things that concerned me in 14 reviewing for this case and in response to Mr. Fell, that's 15 why I kind of folded in Pacific at the same time because 16 they had mentioned it in the testimony, if you base avoided 17 cost rates on "market rates," the implication of market 18 rates is that they are changing continually. That's 19 something, as I say, kind of a generic, and so I think 20 there's some kind of middle ground that will allow companies 21 the ability not to always be stuck with "the wrong rate," be 22 it too high a rate or too low a rate because conditions in 23 the market are changing all the time, and a rate that is 24 firm enough and solid enough and can be relied upon by 25 cogenerators or independent power producers or whoever else 367 CSB REPORTING READING (X-Reb) Wilder, Idaho 83676 Rosebud 1 it is to have enough assurety of a price at a particular 2 time that they can go ahead and develop their project, and 3 so I think that one of the problems that needs to come out 4 of the kind of hearing that I was advocating was the 5 Commission -- to have all the parties have their shot at 6 that and then have the Commission come out and decide what 7 would be proper and what is proper. 8 It's kind of fair to say they shouldn't be 9 changing daily. It's also fair to say they shouldn't be 10 exactly the same number for 10 years without the ability to 11 change them, but that's a pretty big window in there and I'm 12 not sure exactly how to deal with that. 13 Q Would you think that another hearing would be 14 required if the Company wanted to add a new resource or 15 delete one? 16 A I think there's an infinite number of schemes 17 that could be put together. You could put bands in it 18 somehow. You could put a periodic review. You could put 19 some kind of a formula kind of a thing where you put certain 20 variables in or you would put resources in or you would put 21 loads in or you would update it with actual numbers that 22 would tend to tweak it and move it within certain bounds. 23 At some point you would probably need to go 24 back and true things up and redo them again, but I think 25 there's some, for a better term, halfway houses that could 368 CSB REPORTING READING (X-Reb) Wilder, Idaho 83676 Rosebud 1 be put together that you could park these things in so that 2 there's some flexibility, but there's also the assurance 3 that the independent power industry needs to be able to make 4 a project viable. 5 Q But it would be your -- is it your opinion 6 that whatever is used as a base should be on file with this 7 Commission? 8 A Absolutely. 9 MR. WOODBURY: Thank you. Mr. Chairman, I 10 have no further questions. 11 COMMISSIONER MILLER: Mr. Kline. 12 MR. KLINE: Thank you. 13 14 CROSS-EXAMINATION 15 16 BY MR. KLINE: 17 Q I guess it's Page 13 of your testimony, 18 Dr. Reading, the bottom of the page, you're talking about 19 some comparisons that were contained in Idaho Power's 20 acquisition of resources plan. 21 A A little more specific? 22 Q Okay, let's look at Staff Exhibit 108. Have 23 you got that with you? 24 A No, I didn't bring it up. I could get my 25 notebook. 369 CSB REPORTING READING (X-Reb) Wilder, Idaho 83676 Rosebud 1 Q Look on Page 13 of that exhibit, please. 2 A Yes. 3 Q Okay, now, in this section, Idaho Power is 4 comparing the cost of recent Company-owned resources and the 5 cost of QF resources. 6 A Correct. 7 Q And they're comparing them against the cost of 8 purchasing the same amount of power at market prices; 9 correct? 10 A Right. 11 Q All right. Now, in your testimony, you're 12 very critical of this comparison. 13 A Yes. 14 Q And I take you back to Page 13. At that 15 point, you assert that the Company didn't include the 16 capital cost portion of the Company-owned resources when it 17 made the comparison. It only included the variable cost 18 portion; is that correct? 19 A That's my understanding, yes. 20 Q Can you point to anything in Staff Exhibit 108 21 that supports that assumption that capital costs are not 22 included? 23 A I will go through that and then we'll see 24 where we go. What I did is looked at the numbers, went to 25 the FERC Form 1's, pulled out some numbers, did my best to 370 CSB REPORTING READING (X-Reb) Wilder, Idaho 83676 Rosebud 1 make an estimate. Then I went to Staff member Faull and 2 discussed it with him and said what was his understanding of 3 that, and to say that, you may say, well, when we did the 4 comparison, those were included and these are how they were 5 included. That may well be. 6 The problem is that's what this hearing is 7 about and the generic point of my -- not the hearing about, 8 pardon me. What one of the major portions of my testimony 9 is is that we don't know, the Commission doesn't know, the 10 Staff doesn't know and before avoided cost rates should be 11 based on that, we should know. 12 Q Wouldn't it also have been pretty easy to 13 before making the assumption and making the criticism simply 14 to file a discovery request and ask for that information? 15 A I was brought in too late to do that. 16 Q And if in fact it's demonstrated that capacity 17 costs are included in that graph, then your testimony on 18 Page 13 and Page 11 is just wrong, isn't it? 19 A I would retract that, yeah, and to add to 20 that, I would have to see how those capacity costs are 21 included, but in fact if they are there, then I would 22 retract that, yes. 23 Q All right. 24 A I may ask, are they? 25 Q Yes. Well, in describing the assignment that 371 CSB REPORTING READING (X-Reb) Wilder, Idaho 83676 Rosebud 1 you were to follow from Rosebud -- 2 A What they asked me to do? 3 Q Yes, exactly -- what did they tell you about 4 the actual negotiations that took place with Idaho Power? 5 A Virtually nothing. 6 Q Okay. Again, my page references are off so 7 I'm going to have to -- 8 A I apologize. 9 Q Well, someplace in your testimony, you 10 testified that the inclusion of a cost of capital adjustment 11 is not an appropriate subject for negotiations of QF rates 12 for large projects; correct? 13 A As it's currently -- yes, I'd say that's a 14 fair representation. 15 Q And you testify that the Commission -- one of 16 the reasons why that's not appropriate is the Commission has 17 not dealt with this issue explicitly. 18 A Correct. 19 MR. KLINE: This will be Exhibit 215 even 20 though it says 207. 21 (Mr. Ripley distributing documents.) 22 COMMISSIONER MILLER: We'll mark Exhibit 215. 23 (Idaho Power Company Exhibit No. 215 was 24 marked for identification.) 25 Q BY MR. KLINE: And for the record, Exhibit 215 372 CSB REPORTING READING (X-Reb) Wilder, Idaho 83676 Rosebud 1 is a copy of Commission Order No. 25218 in Case 2 No. GNR-E-93-6, and, Dr. Reading, that's one of the orders 3 the Commission issued in the generic PURPA case; is that 4 correct? 5 A That's my understanding. 6 Q And you participated in this case as a witness 7 for IEPI; is that correct? 8 A Yes. There's a whole set of generic orders 9 and I think this is the one I participated in. 10 Q This one has to do with EWGs and cost of 11 capital adjustments. 12 A And the new Energy Act and whether there 13 should be rules or not, yes. 14 Q All right. What I'd like to have you do is 15 take a look at Page 17 of this Order, Dr. Reading. 16 A Okay. 17 Q You will note a highlighted portion. 18 A With a "1" and a circle by it. 19 Q Correct, if you could read that. 20 A Okay. 21 Q And when you're done, I'd like to have you 22 turn to the next page. 23 A Okay. 24 Q And there is a second highlighted portion 25 there; and, finally, if you would turn to Page 3 -- I'm 373 CSB REPORTING READING (X-Reb) Wilder, Idaho 83676 Rosebud 1 sorry, on Page 16 there's also a highlighted portion. 2 A Okay, and this is, I think this section is the 3 part of the proposed rules by the Staff; right? 4 Q Well, this is actually the portion that was 5 adopted by the Commission as their policy statement. 6 A Okay. 7 Q And the question I've got, Dr. Reading, is if 8 you look at on Page 16 -- 9 A Okay. 10 Q -- highlighted Section 3, the Commission has 11 established as a policy a requirement that electric 12 utilities that are proposing to purchase power under 13 long-term wholesale power contracts are supposed to provide 14 the Commission with a cost-benefit analysis at the time that 15 the contract is considered by the Commission for approval; 16 correct? 17 A Right. 18 Q And my question to you is if Idaho Power or 19 any other utility is going to comply with that requirement 20 and if you're dealing with a QF contract that's larger than 21 10 megawatts, it's been negotiated between the parties and 22 it's been signed, unless you negotiate the cost of capital 23 adjustment between the two parties, how are you going to be 24 in a position to respond to the Commission's requirement for 25 a cost-benefit ratio and those kinds of things dealing with 374 CSB REPORTING READING (X-Reb) Wilder, Idaho 83676 Rosebud 1 the utility's cost of capital? 2 A Okay, I won't go through each and every 3 passage. For instance, the one on Page 16 or Page 17 says 4 they should do it if capable of calculation. What I was 5 responding to was the statements in Dr. Willmorth's 6 testimony where he said the number is 2.5 mills per 7 kilowatt-hour adjustment, all right? And I quoted some of 8 it in there. There was a page or two in his testimony that 9 tended to deal with that. 10 The point that I'm trying to make here is that 11 in my mind, the full use of the calculations, assumptions, 12 basis that they came up with such as the -- it's one of the 13 two pages that I handed out. I think it would be the 4 of 5 14 where they use an estimate of what the risk is and they use 15 a generic cost of capital, overall cost of capital, of 10 16 percent; otherwise, there's many parts and pieces of all 17 that that would go into that kind of calculation that I 18 think the Commission has not reviewed, has not looked at, 19 has not dealt with, whether that's proper or improper for 20 Idaho Power to use. 21 In this instance, what I saw was Idaho Power 22 saying we should deduct 2.5 mills per kilowatt-hour for this 23 period and that's what I was objecting to. 24 Q And that was presented by Dr. Willmorth as a 25 part of the rate offer that was made by Idaho Power to 375 CSB REPORTING READING (X-Reb) Wilder, Idaho 83676 Rosebud 1 Rosebud during the course of negotiations; correct? 2 MR. ORNDORFF: Object. He's already testified 3 that he had no knowledge of the negotiations. 4 MR. KLINE: Well, so he -- 5 Q BY MR. KLINE: You don't know, then, whether 6 that was presented as a part of the negotiations? 7 A I think Dr. Willmorth's testimony said it 8 was. Beyond that, I have no knowledge. 9 Q All right, let's assume that Dr. Willmorth's 10 testimony you have correctly recalled it. 11 A Okay. 12 Q As a part of the negotiations, how else are 13 you going to raise that issue unless, for a project larger 14 than 10 megawatts and when you're negotiating, how else are 15 you going to raise that issue and then be able to present it 16 to the Commission unless you have negotiated and perhaps 17 agreed upon it and then presented the contract to the 18 Commission? 19 A I think -- okay, I'm not sure I'm going to 20 answer your question; so if I don't, come back at me, all 21 right? 22 Q Count on it. 23 A What we're doing is taking an individual, 24 specific item that was part of and what I reviewed, not the 25 negotiations but the filing in the case, so we're taking one 376 CSB REPORTING READING (X-Reb) Wilder, Idaho 83676 Rosebud 1 individual, specific item and you're saying how else are we 2 going deal with it unless we put it in. What I saw in a 3 full sense was a whole host of issues which this was one of 4 that were being put on the negotiations and the development 5 of those rates, which in my mind set precedent and change in 6 a macro or huge or whatever the whole playing field of 7 avoided costs and that's what my testimony is objecting to. 8 Q But for projects larger than 10 megawatts 9 where negotiations are expected by the Commission, isn't it 10 appropriate that those whole host of issues be negotiated by 11 the QF and the utility? Isn't that appropriate? Isn't that 12 what they've asked us to do? 13 A Sure, negotiation using the posted rates as 14 the starting point, and what I see happening is how far away 15 from those posted rates do we go or should a utility go in 16 offering the rates to a QF. To me, what has been presented 17 in this filing goes, and as I say in my testimony, I cannot 18 remember the terminology, but beyond the clear intent, 19 beyond the rules of the game, I can't remember what 20 Mr. Packwood used as the terminology, but I think what's 21 been rolled in here with the whole IRP process, and my brief 22 review of your new filing is a whole new way to do it and 23 that isn't where we started and that isn't where the 24 Commission touched from. 25 We're talking about a matter of degree. The 377 CSB REPORTING READING (X-Reb) Wilder, Idaho 83676 Rosebud 1 Commission says you start with the SAR rates and you look at 2 some stuff over here. My objection is it's more than kind 3 of some stuff over here. It's a whole semi-truck full of 4 new stuff that has policy implications, that has items, 5 concepts, issues that are beyond the scope of what the 6 Commission has set down as what should be negotiated with 7 and that's the thrust of my testimony and what I was trying 8 to say. There are all kinds of things in there that the 9 Commission needs to look at and should look at that have 10 implications for avoided costs for everybody, every utility 11 and every other IRP. 12 Q What are some of those things that the 13 Commission is going to have to look at? 14 A What we just discussed here about how to use 15 the cost of capital, those kinds of things. The other 16 examples, I guess I could read through my testimony, but 17 those others are, back to Mr. Fell's question, you know, 18 what's the definition of market-based rates, what are they, 19 how should they be used. Should a least cost planning 20 process be used or should a surrogate resource be used. 21 What kind of surrogate resource should be used. Do you want 22 me to keep going? 23 Q Are you done? 24 A I just gave you a non-exclusive list. If I 25 thoughts some more, I could think about them. 378 CSB REPORTING READING (X-Reb) Wilder, Idaho 83676 Rosebud 1 Q And it's your testimony that all of those 2 things would be off limits for negotiations between the 3 utility and the QF? 4 A Not necessarily, no. You know, to be kind of 5 pregnant, we're talking about degrees here. As I understand 6 what the Commission orders say is that for QFs larger than 7 10 megawatts, you start with the posted rates and then fuss, 8 okay? And to me, there's a big difference between coming in 9 with essentially Idaho Power's new filing to change things 10 and fussing with the rates. That isn't to say that anything 11 is open to negotiations. It's how close given the current 12 Commission's orders, how much do you fuss with it. 13 MR. KLINE: That's all the questions I have. 14 COMMISSIONER MILLER: Commissioner Nelson. 15 COMMISSIONER NELSON: I don't have any. 16 COMMISSIONER MILLER: Commissioner Smith. 17 COMMISSIONER SMITH: Okay, only because I know 18 Don would be very disappointed if I didn't have questions. 19 THE WITNESS: Thank you, Commissioner. 20 21 EXAMINATION 22 23 BY COMMISSIONER SMITH: 24 Q All right; so let's assume that you're right, 25 you start with the set SAR and you're going to tinker with 379 CSB REPORTING READING (Com-Reb) Wilder, Idaho 83676 Rosebud 1 it a little. 2 A Right. 3 Q And assume that what the Company wanted to 4 negotiate here was beyond the scope of the anticipated 5 adjustments; so you have that on one side, but then assume 6 that the changes that the Company has seen and wants to 7 adjust are real and are true and are actual. 8 A Okay. 9 Q So what do you do with that? I mean, who is 10 going to bear the penalty, so to speak, if the Commission 11 requires the Company to enter into this firm contract given 12 the circumstances have actually changed? I mean, even if 13 you argue that the Company should have come in last year or 14 18 months ago and started a proceeding, I mean, who's going 15 to bear the penalty and why should you make them? 16 A Okay, that's a good question and I will make 17 an implicit assumption that works against what I'm saying, 18 but I'll make an implicit assumption that the Company is 19 correct that these rates are "too high" because I'm 20 assuming, I haven't looked at it that much, but I assume the 21 new filed rates over the IRP are less than what's there. 22 Well, the obvious answer with a tracker is to the extent 23 that the Company is correct, the ratepayers will bear that 24 burden. 25 Q That's right. 380 CSB REPORTING READING (Com-Reb) Wilder, Idaho 83676 Rosebud 1 A Okay, to the extent the Company is not correct 2 and this is over a 20-year contract a good resource and 3 prices go up like crazy 10 years down the road, then it's a 4 good deal over the long run. I think that in this case that 5 isn't really different than what we deal with in regulation 6 every day and that is that no matter how hard you try, 7 anything you fix, even if you do it perfectly and we don't, 8 it's going to be wrong tomorrow because things change. 9 Let me use an example. I noticed in Idaho 10 Power's filing on the IRP process, they used a return on 11 common equity of 12.79 percent and then they did their 12 calculations and came up with that. Well, I live in this 13 world and I do this and I think personally that that's 14 wrong, that given today, I haven't done the full analysis, 15 but given what's going on around the country, 12.8 percent 16 is too high a return on common equity, all right? So I 17 don't think Idaho Power deserves the rates they're getting 18 because that's too high a common equity. I don't have the 19 right in January when they send me the bill to discount that 20 and send it to them. I mean -- 21 Q I guess I'm missing the analogy, Dr. Reading, 22 but if you could get back to this case -- 23 A What I'm saying is that we make rules and we 24 set rates. As things change, those rates are too high, 25 those rates are too low. Because they're high or low, 381 CSB REPORTING READING (Com-Reb) Wilder, Idaho 83676 Rosebud 1 certain groups, shareholders, customers, customers within 2 classes, independent power producers, consumers -- 3 Q So now we're back to process, aren't we? 4 A Right. 5 Q Now the question is what is the appropriate 6 process and I assume you will agree with me that the 7 Commission can change its mind about rate of return -- 8 A Certainly. 9 Q -- and about the SAR. 10 A Absolutely. 11 Q So the question is what is the process 12 necessary, then, to accomplish that. 13 A The process that I understand is until those 14 things are changed what's there is the law and should be 15 followed. 16 COMMISSIONER SMITH: Thank you, Mr. Chairman. 17 18 EXAMINATION 19 20 BY COMMISSIONER MILLER: 21 Q Let me see if I can follow up along those 22 lines and also along the lines of Mr. Kline's concluding 23 questions having to do with the topic or the question of the 24 scope of permissible negotiations for large projects. I 25 just want to see if I can get some clarity in my own mind as 382 CSB REPORTING READING (Com-Reb) Wilder, Idaho 83676 Rosebud 1 to exactly what your position on that topic is. I take it 2 your first point is that the starting point for negotiations 3 is, we'll say, Appendix A; correct? 4 A Right. 5 Q So the next question is if that's the starting 6 place, then what is the scope of permissible negotiations 7 from that point, and I take it that you would probably agree 8 that matters which are not included in Appendix A or not 9 included within the assumptions of Appendix A, such as 10 dispatchability, location of the project, could be matters 11 that could be within the scope of permissible negotiations; 12 is that fair so far? 13 A Within the scope of negotiations, yes. 14 Q The harder question, though, is to what extent 15 can you negotiate matters that are within the assumptions of 16 Appendix A. 17 A Yes. 18 Q And you offer kind of a fuss rule. You can 19 fuss but not fight or I'm not quite sure. I guess what I'm 20 trying to get is a more specific definition of what your 21 fuss rule really would be; that is, can you negotiate within 22 a 10 percent parameter of those assumptions? What are the 23 parameters that fence in the scope of permissible 24 negotiations in your view? And before you answer, I should 25 predicate this question by saying that this assumes that 383 CSB REPORTING READING (Com-Reb) Wilder, Idaho 83676 Rosebud 1 that question has not been decided and assuming that we were 2 trying to decide that question de novo when in fact it's 3 arguably been decided, but let's assume for just our 4 purposes of this question that we're writing on a fresh 5 slate here and what would be your advice on how to define 6 the boundaries of permissible negotiations with respect to 7 assumptions that are included in Appendix A? 8 A I can't give you a specific answer. Let me 9 try to approach it a little better because I think there's a 10 rule of reason or judgment or whatever that's involved 11 here. I think to answer a little bit out of context, what I 12 think you're saying and that is it's open to negotiations, 13 everything is open to negotiation. I could think of some 14 kind of a unique contract, somebody might come in with some 15 kind of a windmill or something else that would be all 16 dispatchable or whatever; so in that sense, they're all open 17 between the parties. 18 I think the question that is finer here is how 19 much should an independent power producer bringing a project 20 to the Company, how much right do they have to have those 21 rates adjusted some, okay? And I'm sorry, Commissioner, I 22 can't really specifically define where that line is. I 23 think in my judgment reading what's in the record from Idaho 24 Power in this particular case, it goes beyond those bounds. 25 The strict bounds would be to give the rates that are posted 384 CSB REPORTING READING (Com-Reb) Wilder, Idaho 83676 Rosebud 1 period. You know, you used 10 percent. Well, okay, 2 10 percent, 15 percent, I don't know. That's a hard 3 question and I think that's what the Commission is 4 struggling with and I think that's one of the key elements 5 right here. 6 Q Perhaps this is an unfair question and perhaps 7 you're not prepared to comment on it, but conceivably, I'm 8 not saying this is necessarily the case, but conceivably, 9 the existing rule either is or should be that the Exhibit A 10 assumptions are the Exhibit A assumptions and they're not 11 negotiable, you only negotiate things over and above or 12 outside of Exhibit A, apparently, that's not your 13 contention? 14 A No, I think there's some room for negotiation 15 there, and as I understand, and, again, I'm getting over 16 where my knowledge isn't that good, but for instance, the 17 Auger Falls and Meridian contract aren't exactly Schedule A 18 and as was indicated in the letter and why Mr. Faull has 19 submitted the substitute pages in his testimony, Rosebud has 20 said they're willing to accept that; so that's outside those 21 strict boundaries. Now, how much beyond that, I mean, I'm 22 not really sure. What I say I do feel confident about is 23 what the Company has brought in is beyond those bounds. How 24 much you back up from that I'm not sure. 25 Q And before you go, do you have any further 385 CSB REPORTING READING (Com-Reb) Wilder, Idaho 83676 Rosebud 1 thoughts on, maybe we're just going over the same thing 2 here, but any further thoughts on a definition or a test for 3 deciding or defining where the boundary line between 4 acceptable changes to Appendix A assumptions for negotiation 5 purposes is and being able to recognize when you've crossed 6 over the boundary? 7 A I won't bore you with all the similes I could 8 bring up, but, no, I cannot think of a way to specifically 9 define that. 10 COMMISSIONER MILLER: Redirect. 11 MR. ORNDORFF: Mr. Chairman, I have no 12 questions. 13 COMMISSIONER MILLER: Thank you, 14 Mr. Orndorff. 15 Dr. Reading, thank you for your help. Can 16 this witness be excused? 17 MR. KLINE: Fine with me. 18 COMMISSIONER MILLER: In the absence of 19 objection, you're free to come and go as you wish. 20 (The witness left the stand.) 21 COMMISSIONER MILLER: Mr. Orndorff, does that 22 bring us to the conclusion of your presentation? 23 MR. ORNDORFF: Yes, it does, Mr. Chairman. 24 COMMISSIONER MILLER: Thank you. My proposal 25 now would be to take the PacifiCorp witness. Mr. Fell. 386 CSB REPORTING READING (Com-Reb) Wilder, Idaho 83676 Rosebud 1 MR. FELL: Yes, PacifiCorp's witness is 2 Mr. Rodger Weaver. 3 4 RODGER WEAVER, 5 produced as a witness at the instance of PacifiCorp, having 6 been first duly sworn, was examined and testified as 7 follows: 8 9 DIRECT EXAMINATION 10 11 BY MR. FELL: 12 Q Mr. Weaver, would you please state your name, 13 business address and present position with PacifiCorp? 14 A Yes. My name is Rodger Weaver. My business 15 address is 920 S.W. Sixth Avenue, Portland, Oregon, and I'm 16 the power systems regulation manager with the company. 17 Q Mr. Weaver, are you sponsoring exhibits 18 numbered -- perhaps before I conclude this question, 19 Mr. Weaver has three exhibits that are identified as RW-1, 20 RW-2 and RW-3. The numbers for those should be 301, 302 and 21 303. Exhibit 301 is a two-page exhibit and the others are 22 one-page exhibits. 23 Mr. Weaver, are you sponsoring Exhibits 301, 24 302 and 303? 25 A Yes, I am. 387 CSB REPORTING WEAVER (Di) Wilder, Idaho 83676 PacifiCorp 1 Q If I were to ask you the questions contained 2 in your prefiled testimony, would your answers today be the 3 same? 4 A Yes, they would. 5 MR. FELL: I move that Mr. Weaver's testimony 6 be spread on the record as if read. 7 COMMISSIONER MILLER: In the absence of 8 objection, it's so ordered. 9 MR. FELL: And I also move that the exhibits 10 be marked as I have read. 11 COMMISSIONER MILLER: Exhibits 301, 302 and 12 303 will be marked. 13 (The following prefiled testimony of 14 Mr. Rodger Weaver is spread upon the record.) 15 16 17 18 19 20 21 22 23 24 25 388 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 address 4 is PacifiCorp, 920 S.W. Sixth Avenue, Portland, Oregon. I 5 am the Power Systems Regulation Manager for the Company. 6 Q Please briefly describe your education and 7 business experience. 8 A I received a Bachelor of Arts degree in 9 Economics and a Ph.D. in Economics from the University of 10 Utah. I was previously employed by the Utah Division of 11 Public Utilities as a Senior Economist. I have been 12 employed by PacifiCorp for one year. 13 Q Please describe your present duties. 14 A I am responsible in this proceeding for 15 presenting the Company's position on avoided costs as they 16 relate to qualifying facilities (QFs) and other potential 17 resource acquisitions. My regular duties include directing 18 and coordinating net power cost studies and related 19 analyses. I also represent the Company on Power Resource 20 issues and information before the various regulatory 21 commissions. 22 Q Please describe the purpose of your testimony. 23 A Rosebud Enterprises contends, in this case and 24 a similar complaint proceeding against Utah Power & Light 25 Company (Utah Power), that prices payable for qualifying facilities larger than 10 MW must be determined based upon 389 Case No. IPC-E-92-3 R. Weaver, PacifiCorp 1 the Surrogate Avoidable Resource (SAR) methodology. It is 2 the Company's opinion that actual, market-based alternative 3 costs must be used as the basis for negotiation of such 4 prices. I will show that the costs which a potential QF 5 would allow the Company to avoid are related to currently 6 available market options and not necessarily to the filed, 7 published avoided costs, and that the differences are 8 substantial. 9 Q Why is this difference in approach 10 significant? 11 A There have been important changes in the 12 electric power supply market since the Commission adopted 13 SAR-based avoided costs. The two changes that are most 14 significant are the large increase in available supply and 15 the marked reduction in costs. These changes have occurred 16 rapidly and have accelerated over the last 6 to 12 months, 17 in part due to changes in federal legislation which 18 encourages resource development by nonutility sources. For 19 example, when the Company received responses to its 20 competitive bidding solicitation in early 1992, few of the 21 resources were offered at prices below full avoided costs. 22 Based on these results, the Company concluded at that time 23 that the SAR-based avoided costs were still a reasonable 24 representation of the Company's resource alternatives. In 25 contrast, recent proposals representing more than 3,000 megawatts have been submitted to the Company by resource 390 Case No. IPC-E-92-3 R. Weaver, PacifiCorp 1 developers at prices between 70 and 90 percent of SAR- 2 based avoided costs. The Company has had extensive 3 discussions and negotiations with several of these 4 developers and has concluded that the developers are 5 capable of delivering what they have proposed. Based on 6 these recent proposals, the Company no longer believes that 7 the SAR-based avoided costs reasonably represent the 8 Company's resource alternatives. 9 Q Is the SAR method inappropriate? 10 A Not necessarily. The Company's concern is not 11 with the SAR method itself; rather, the concern is that any 12 administratively determined avoided costs cannot keep pace 13 with the changes in the current electric power supply 14 market. Therefore, the Company supports administratively 15 determined avoided costs for small projects and market based 16 alternative costs for larger projects where the financial 17 impact becomes more significant. 18 Q What do you mean when you refer to 19 market-based alternative costs? 20 A For the purposes of this testimony, 21 market-based alternatives are resources which fall into two 22 categories: Company-owned resource options and resource 23 options proposed to the Company by outside developers. This 24 market is what ultimately determines the available pricing 25 alternatives for evaluating potential resource options. 391 Case No. IPC-E-92-3 R. Weaver, PacifiCorp 1 Use of market-based resource costs in the evaluation of 2 projects results in a determination of a project's value to 3 the Company's system that leaves ratepayers indifferent to 4 whether the Company acquires available market resources or 5 the output of a QF. 6 Q Can you give an example of a new Company-owned 7 market-based resource option? 8 A Yes. The James River Camas Mill Cogeneration 9 Project is a new Company-owned resource developed by 10 PacifiCorp in conjunction with an outside party, the James 11 River Corporation. 12 The James River project is a 50 megawatt cogeneration 13 project located at James River's paper mill in Camas, 14 Washington. The project will use steam produced for the 15 paper making process to drive a turbine-generator. It 16 will provide PacifiCorp a highly efficient source of 17 generation close to the Portland metropolitan area load 18 center. PacifiCorp will own the plant and be responsible 19 for periodic major maintenance costs; James River will 20 construct and operate the plant and provide routine 21 maintenance. 22 Q Please describe the outside developer market 23 currently available to the Company. 24 A In late 1991, PacifiCorp issued a formal 25 Request for Proposal (RFP) for resource acquisitions. PacifiCorp 392 Case No. IPC-E-92-3 R. Weaver, PacifiCorp 1 received 47 proposals, which offered 1104 average MW to the 2 Company. Another RFP will be issued in 1994 as per 3 Washington Utilities and Transportation Commission 4 requirements. In addition to proposals received through 5 the formal RFP process, the Company receives numerous 6 unsolicited proposals. These potential resources include 7 gas-fired combustion turbines, cogeneration facilities, 8 geothermal plants, and hydro facilities, as well as 9 demand-side resources. Thus, they offer the Company a 10 varied group of potential resource options. Exhibit 301 11 (RW-1) lists a number of currently active resource 12 proposals by location and size. 13 Q How do the prices associated with the projects 14 discussed above compare to the Company's filed avoided costs 15 using the SAR methodology? 16 A Exhibit 302 (RW-2) shows a comparison of the 17 Company's filed avoided costs with the price streams for the 18 James River project, a hydro project currently under 19 negotiation, a "typical" thermal project, and a high and 20 low unsolicited proposal. The exhibit shows that costs 21 associated with these resources are in the range of 70% to 22 90% of the currently approved Idaho avoided costs on a 23 20-year levelized basis. 24 Q Please describe the hydro project that is 25 under negotiation. 393 Case No. IPC-E-92-3 R. Weaver, PacifiCorp 1 A The hydro project is an approximately 5 MW 2 plant located on the East side of the Company's system. It 3 was brought to the Company's attention through the RFP 4 process and is considered a very viable project. The prices 5 stated are those offered by the resource developer. 6 Q Please describe the "typical" thermal project. 7 A The "typical" thermal project is a gas-fired 8 cogeneration project of approximately 220 MW. It is based 9 upon a gas-fired cogeneration project offered to the Company 10 for which there is an executed Memorandum of Understanding. 11 The offered project will use two gas-fired turbines and have 12 a capacity of approximately 450 MW. It is associated with 13 existing manufacturing facilities and will be located on the 14 West side of the Company's system. 15 The "typical" project is shown at 220 MW because other 16 proposals employing this technology are likely to be 17 installed in single turbine configurations. The Company is 18 currently considering gas-fired cogeneration proposals of 19 this type representing approximately 3,000 MW. The majority 20 of these projects would be located on the West side of the 21 Company's system. 22 The capacity factor and prices for the "typical" project 23 are derived from the Memorandum of Understanding 24 for the 450 MW project. To protect against disclosure of 25 the year-to-year prices of the proposed project, the 394 Case No. IPC-E-92-3 R. Weaver, PacifiCorp 1 year-by-year prices of the "typical" project have been 2 modified somewhat. The levelized price, difference in 3 levelized price from the Idaho avoided costs, and percent of 4 Idaho avoided costs are very similar to the actual project. 5 Q Please discuss the dollar impact of these 6 price steams. 7 A Exhibit 303 (RW-3) compares the 20-year cost 8 streams of a hypothetical 10 MW resource with a 90% capacity 9 factor priced at the Company's filed avoided costs with the 10 same project priced at the Typical Thermal Project prices 11 from Exhibit 302 (RW-2). The difference between the two 12 cost streams, which represents costs in excess of 13 market-based levels, is approximately $30 million or 14 approximately $10 million on a present value basis. In the 15 case of a 40 MW project, such as Rosebud proposes to 16 construct, this financial impact would be four times as 17 great. 18 Q How does market-based alternative pricing 19 affect other jurisdictions? 20 A Under the current interjurisdictional cost 21 allocation method for PacifiCorp, QF costs are allocated 22 system-wide. A key understanding in the development of this 23 method was that all states would have similar QF costs on 24 a going-forward basis. 25 Q Have you been involved in the Allocation Task 395 Case No. IPC-E-92-3 R. Weaver, PacifiCorp 1 Force work that developed the current allocation method? 2 A Yes. I have attended all PacifiCorp 3 Interjurisdictional Task Force Allocation (PITA) meetings 4 and I was a member of the PITA Executive Committee from its 5 formation until June of 1992. 6 Q Please briefly describe the history of the QF 7 cost allocation methods used since the merger of Utah Power 8 and PacifiCorp in 1989. 9 A Initially, there was concern that some states 10 would be asked to pay higher than acceptable costs from 11 qualifying facilities in other states. This concern led to 12 the adoption in the first two post-merger allocation methods 13 (Interim and Consensus) of an approach which assigned part 14 of the higher pre-merger QF costs to the division of origin 15 while allocating all post-merger QF costs system wide. The 16 theory behind this approach was that all post-merger QF 17 costs would reflect system-wide value in all states. 18 The PITA Accord Method, which is currently in place, was 19 then developed as a result of materiality and fairness 20 considerations. Under the Accord Method all QF costs (pre- 21 and post-merger) are allocated system-wide with the key 22 expectation that all post-merger QF costs will represent 23 system-wide value in all states. 24 Q How does the PITA Accord Method relate to the 25 discussions within this testimony? 396 Case No. IPC-E-92-3 R. Weaver, PacifiCorp 1 A If one or more jurisdictions has higher QF 2 costs than other jurisdictions and the amounts are material, 3 the other states may reconsider and decline to accept their 4 share of QF costs. This would necessitate a change in the 5 interjurisdictional allocation method if PacifiCorp is to be 6 allowed a reasonable opportunity to recover its costs. 7 Q Would the use of market-based alternative 8 resource pricing alleviate the potential QF cost 9 inconsistencies between jurisdictions? 10 A Yes. Determining the value of a potential 11 project using market-based alternative costs helps to 12 protect all jurisdictions from being asked to accept higher 13 than necessary costs. 14 Q Are there other interjurisdictional issues 15 relating to QF pricing differences among the states? 16 A Yes. In addition to potential inequities in 17 allocated QF costs, the availability of higher prices in one 18 jurisdiction creates a magnet effect for potential 19 qualifying facilities in neighboring states, encouraging 20 potential projects to move their point of delivery to the 21 state within PacifiCorp's system with the highest avoided 22 costs. This places unfair burdens on customers in all 23 jurisdictions, who then pay the additional costs. The use 24 of market-based costs would allow the consideration of the 25 397 Case No. IPC-E-92-3 R. Weaver, PacifiCorp 1 project's value and cost system-wide and would help to deter 2 this shifting of the point of delivery. 3 Q Is it appropriate to use market-based 4 alternative costs in the pricing development of all 5 potential resources? 6 A Not necessarily. PacifiCorp is striving to 7 balance the objectives of the Public Utility Regulatory 8 Policies Act of 1978 with the need to protect customers from 9 paying too much for these resources. PacifiCorp feels that 10 the time and cost involved in analyzing all of the 11 operational characteristics of smaller projects, which we 12 define as projects of one megawatt or less, as well as other 13 costs associated with such projects may be an impediment to 14 their development unless a standard rate is available. 15 Therefore, these smaller projects should use the standard 16 administratively determined avoided cost for pricing. 17 Larger projects should be required to negotiate avoided cost 18 prices based on what is otherwise available to the Company 19 in the market. 20 Q Is the price of alternative resources the only 21 consideration in such negotiations? 22 A No. These negotiations also take into account 23 the location, size, operational characteristics, fuel 24 source, reliability, and any other factors that influence 25 the project's value to the rest of the system as well as the costs which the project would allow the Company to avoid. 398 Case No. IPC-E-92-3 R. Weaver, PacifiCorp 1 Q How does location impact the value of a 2 potential resource on the Company's system? 3 A In general, the Company's system resource 4 needs are greater on the West side of the system than on the 5 East side. Potential resources located on the East side of 6 the Company's system would need to consider the transmission 7 cost of moving the project's output to the West side. 8 Because of limits on available transmission, the need to 9 wheel power from East to West could decrease the value of 10 the potential East side resource. From an electrical 11 perspective, projects in southeastern Idaho (Utah Power's 12 service territory) are located on the East side of the 13 Company's system. A project that is located in a high load 14 area would have higher value than one located in a 15 transmission bottlenecked area. 16 Q What is your conclusion? 17 A It is the Company's opinion that actual, 18 market-based alternative costs should be used to establish 19 prices for QFs that do not qualify for administratively 20 determined avoided costs. Using any administratively 21 determined avoided cost methodology which does not reflect 22 current market conditions simply cannot reflect the resource 23 costs that are avoidable. Using market-based alternative 24 costs presents a more accurate view of the costs that the 25 utility can avoid by acquiring the output of a particular 399 Case No. IPC-E-92-3 R. Weaver, PacifiCorp 1 project and protects the Company and all of its customers 2 from unnecessarily high costs. For larger QF projects, the 3 difference between pricing on the basis of administratively 4 determined avoided costs and on the basis of market-based 5 alternatives is significant in terms of costs to be borne by 6 the Company and its customers. 7 Q Does this conclude your testimony? 8 A Yes. 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 400 Case No. IPC-E-92-3 R. Weaver, PacifiCorp 1 (The following proceedings were had in open 2 hearing.) 3 MR. FELL: Mr. Weaver is available for 4 cross-examination. 5 COMMISSIONER MILLER: All right, let's start 6 with Mr. Burleigh. 7 MR. BURLEIGH: No questions. 8 COMMISSIONER MILLER: Mr. Richardson. 9 MR. RICHARDSON: No questions for this 10 witness, Mr. Chairman. 11 COMMISSIONER MILLER: Mr. Kline. 12 MR. KLINE: I have no questions for this 13 witness. 14 COMMISSIONER MILLER: Mr. Woodbury. 15 MR. WOODBURY: Thank you, Mr. Chairman. 16 17 CROSS-EXAMINATION 18 19 BY MR. WOODBURY: 20 Q Mr. Weaver, directing your attention to 21 Page 2, Line 24 of your testimony, you speak of recent 22 proposals representing more than 3,000 megawatts have been 23 submitted to the Company by resource developers. You 24 operate in a seven-state area? 25 A That's correct. 401 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 Q And is this a total system number? 2 A Yes, it is. 3 Q And was this the result of a request for 4 proposals in a number of your states? 5 A No, this is beyond the proposals that came in 6 as a result of the RFP. 7 Q This does not include your RFP? 8 A That's correct. 9 Q Has the Company had an RFP since October 1 of 10 1990? 11 A Of '91 it was and, no, we'll submit our next 12 one in '94. 13 Q No, my question was since October 1 of 1990, 14 have you had any requests for proposals and you said it was 15 in '91? 16 A Yes. 17 Q And didn't the company accept any resources as 18 a result of that request? 19 A We accepted, I don't remember the exact 20 numbers, we accepted some resources as a result of that RFP, 21 yes. 22 Q Do you know how many average megawatts? 23 A I wasn't with the company at the time. I 24 believe that it's on the order of around 12.5 megawatts. 25 Q You state on Page 3, Line 6, that the Company 402 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 no longer believes that the SAR-based avoided costs 2 reasonably represent the company's resource alternatives. 3 When did the Company first come to that realization? 4 A As I discuss in my testimony, the market has 5 been evolving quite rapidly. As the resources have come to 6 us outside of our formal solicitation over the last year or 7 so, we've come to realization that the existing SAR-based 8 avoided cost resources are higher than what our 9 market-oriented avoidable alternatives are. 10 Q One of the reasons that you cite for your 11 position is that administratively-determined avoided costs 12 in the company's perception cannot keep pace with the 13 changes in the current electric power supply market; is that 14 correct? 15 A That's correct. 16 Q And the changes that you're referring to you 17 have discussed in your testimony? 18 A Yes. 19 Q Referring to your Exhibit 301, this 20 represents -- does this represent contracts that you have 21 signed or only projects that have contacted or QF developers 22 that have contacted you or other resource suppliers? 23 A These represent developments whose sponsors 24 have contacted us. None of these represent currently signed 25 contracts with the exception of the U.S. Gen, Hermiston, one 403 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 listed on the first page. 2 Q How large is that? 3 A It says 470 megawatts, 474 megawatts. 4 Q And is this rated capacity or average 5 megawatts to the company's system? 6 A That's capacity. 7 Q Are you familiar with the PacifiCorp's 8 Appendix A resource schedule that's on file with this 9 Commission? 10 A Reasonably so. 11 Q Do you believe that that resource schedule is 12 current? 13 A No. 14 Q Do you believe -- do you know what the 15 company's trigger is? 16 A It was on the order of 90 megawatts. 17 Q I think it was 80 average megawatts. 18 A Okay. 19 Q Do you know since this schedule was first 20 published in October 1 of 1990 whether the company has 21 acquired average megawatts approaching 80? 22 A We have, yes. 23 Q And do you have in your mind an idea as to the 24 total number of average megawatts the company has acquired? 25 A It would be several hundred. 404 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 Q It appears to me that PacifiCorp is in here 2 indicating that the administrative avoided cost methodology 3 that we have in place is not working because the Commission 4 cannot respond quickly enough, and can you explain why the 5 company did not approach the Commission and indicate that 6 its trigger had been reached and seek to adjust its rates? 7 A In our evaluation up until quite recently, as 8 I indicated a while ago, our view was that our resource 9 acquisitions, especially since a substantial number of them 10 also included companion off-system sales, firm off-system 11 sales, for a period of time, may not have resulted in a 12 substantial change in filed avoided costs had we proceeded 13 with filings to get the avoided costs changed and, hence, 14 elected not to proceed with those. 15 Q Are you aware that under the current 16 Appendix A schedule that's filed for 1993 it shows a deficit 17 of 161 average megawatts and for 1994 228? 18 A Yes. 19 Q Is it the company's position that they are in 20 deficit at this point? 21 A No, it is not. I would point out that those 22 filings you refer to continue to assume the 3 percent per 23 year growth rates which in fact don't represent what the 24 company's growth rates have actually been. They've been 25 substantially below that. 405 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 Q And when you say substantially, how much 2 below? 3 A On the order of, in the range of 2 percent per 4 year. 5 Q Referring again to your Exhibit 301, Page 2, 6 under Idaho -- 7 A Yes. 8 Q -- you're engaged in active negotiation with 9 all of those parties? 10 A We're actively engaged with Island Park, 11 Montpelier, I mean Rosebud in perhaps some interpretation, 12 and Firth Cogeneration. I don't believe that we're still 13 engaged in active negotiation with either Gibson or Simplot. 14 Q And so those amounts should be deleted for a 15 total of 25 megawatts? 16 A No, I don't think so. They're still alive 17 projects. They're just not under active pursuit by anyone 18 at this time. 19 Q Has PacifiCorp signed any contracts for QF 20 generation in Idaho since October 1st of 1990? 21 A I believe not. I would have to check for 22 sure, but I believe not. 23 Q I'm not sure when the Fall River contract, 24 that seems like that was executed with UP&L and then 25 subsequently rescinded. 406 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 A Like I said, I believe the answer to your 2 question is no, but I could verify that for sure. 3 Q Okay. On Page 10, Line 14, when you speak of 4 larger projects should be required to negotiate avoided cost 5 prices based on what is otherwise available to the company 6 in the market, when you're speaking of larger projects, 7 you're speaking of projects greater than one megawatt? 8 A That as is probably well known is our view of 9 the matter, but in general, whatever projects are not 10 eligible for administratively-determined avoided costs we 11 believe should negotiate on that basis. 12 Q When you say "based on what is otherwise 13 available to the company in the market," what do you mean? 14 A What I'm referring to is the fact that 15 developers now outside of any formal solicitation actively 16 approach this company and other companies with a large 17 number of what could be referred to as high quality 18 proposals and it's that market that we're talking about 19 referring to as the basis for negotiation. 20 Q Mr. Weaver, has PacifiCorp filed an avoided 21 cost case with this Commission? 22 A We have not. We're in the final stages of 23 preparation of that case right now. 24 Q It was my understanding that it would be filed 25 today. 407 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 A That was our intent, but we didn't make it. 2 MR. WOODBURY: Thank you. Mr. Chairman, I 3 have no further questions. 4 COMMISSIONER MILLER: All right. 5 Mr. Kline, did I ask you? 6 MR. KLINE: You did and I have no questions. 7 COMMISSIONER MILLER: We're to Mr. Orndorff, 8 then. 9 MR. ORNDORFF: Mr. Chairman, before I tell you 10 I don't have any further questions, I would like to show on 11 the record that the questions that I would ask would have to 12 do with at least two other cases, and maybe three, to be 13 filed and I don't think given the Commission's direction 14 that it's appropriate to stray too far from the Complaint 15 proceeding; so with that, I will not ask any cross, but with 16 more latitude I would have. 17 COMMISSIONER MILLER: We appreciate your 18 restraint. 19 Commissioner Nelson. 20 COMMISSIONER NELSON: I do have just a couple 21 of questions. 22 23 24 25 408 CSB REPORTING WEAVER (X) Wilder, Idaho 83676 PacifiCorp 1 EXAMINATION 2 3 BY COMMISSIONER NELSON: 4 Q Mr. Weaver, on your Exhibit 301 where you list 5 the potential projects, apparently in Idaho some of those 6 projects haven't seen any recent activity. Do you know of 7 this two-page list what is likely to be signed in, say, the 8 next quarter or six months? 9 A A very small portion would be signed in that 10 amount of time. You'll notice that we're talking here about 11 almost 9,000 megawatts. We have no need for anything like 12 such a large magnitude. As I said, the Hermiston in Oregon 13 project was recently signed. Within the next six months I 14 think there's a really good chance that probably the Firth 15 project has a good chance of being signed. 16 Q The Firth cogeneration project? 17 A Yes. The Clark Canyon in Montana, as you're 18 aware, we've had a discussion with this Commission about it, 19 may, if it comes real, become something that we sign 20 relative soon. 21 Q Is that also known as the Island Power? 22 A Island Power, yes. I wouldn't hold out any of 23 the others as near-term signing probabilities. 24 Q So in addition to the Hermiston project, 25 there's a possibility that you might sign contracts for 409 CSB REPORTING WEAVER (Com) Wilder, Idaho 83676 PacifiCorp 1 15 megawatts? 2 A Within the short period of time you suggest. 3 Q On Page 9 of your testimony, you make the 4 statement that the higher prices that Idaho has in contrast 5 to the surrounding states creates a magnet effect. I assume 6 you're talking about the Island Power project? 7 A That was a case in point. 8 Q Have you signed any contracts that would 9 reflect this situation in the last several years that you 10 know of? 11 A No. 12 COMMISSIONER NELSON: Okay, thank you. That's 13 all I have. 14 COMMISSIONER MILLER: Commissioner Smith. 15 COMMISSIONER SMITH: I have no questions. 16 Thank you. 17 18 EXAMINATION 19 20 BY COMMISSIONER MILLER: 21 Q Just one topic which may not be completely 22 relevant here, but, nonetheless, I believe in response to a 23 question from Mr. Woodbury, you indicated that, to your 24 knowledge, PacifiCorp has not signed any QF contracts with 25 producers during the period of 1991 to present; is that 410 CSB REPORTING WEAVER (Com) Wilder, Idaho 83676 PacifiCorp 1 correct? 2 A In the State of Idaho. 3 Q In the State of Idaho. 4 A Yes. 5 Q Do you recall off the top of your head the 6 total PP&L-Idaho jurisdictional load in Idaho? 7 A Thinking in percentage terms, Idaho 8 constitutes something like 8 percent of our total load, 9 which itself is something like 7,000 megawatts. 10 Q So 8 percent of 7,000 would be approximately 11 how many megawatts? You're much better at math than I am, 12 I'm sure. 560? 13 A 560, on that order. 14 Q And do you recall off the top of your head the 15 total QF production in Idaho currently under contract to 16 meet that load? 17 A I believe, if any, it's extremely small. We, 18 of course, meet all of our jurisdictions' load requirements 19 from all system resources, wherever they're located. 20 There's no assignment of -- 21 Q Certainly. If, though, just for purposes of 22 an analysis we were trying to look at the amount of QF 23 production in Idaho to meet the Idaho jurisdictional load, 24 is there any? 25 A I believe not at the moment. After having 411 CSB REPORTING WEAVER (Com) Wilder, Idaho 83676 PacifiCorp 1 said that, I'm playing back a little bit of memory. I think 2 that Utah Power did have before the merger a few small hydro 3 QF resources in the state. Again, I'd have to check, but it 4 is the case that they're not very large, if they exist. 5 Q Putting these answers in the context of your 6 testimony on Page 3 where you advocate the use of 7 market-based alternatives for larger projects where the 8 financial impact becomes more significant, it would appear 9 to me given the answers we've just gone over that for 10 PacifiCorp there is some distance to go before a financial 11 materiality test or before the burden of QF production would 12 become financially material for PacifiCorp, at least in 13 Idaho; would that be a fair statement? 14 A I certainly, agree with that and I think the 15 distance we would have to go would be exactly one large QF 16 development. Going from none to a large QF that imposes, as 17 I've indicated, an increase in costs relative to market of 18 something like $3 million a year over a 20-year period of 19 contract, immediately in my mind becomes material. It's on 20 a going forward basis that we have the concern, not 21 historically, which is to some extent the basis of my 22 response to Mr. Woodbury. We haven't seen the problem in 23 the past. We see it coming in the future. 24 COMMISSIONER MILLER: Okay, thanks. I have 25 ignored my admonition to stay focused on the facts of this 412 CSB REPORTING WEAVER (Com) Wilder, Idaho 83676 PacifiCorp 1 Complaint case, but we'll go to redirect. 2 MR. FELL: Mr. Chairman, if we are able to 3 determine what the level of QF investments in Idaho have 4 been over the last few years, we will try to find out the 5 answer to that question, that was left open, but, otherwise, 6 I have no redirect. 7 COMMISSIONER MILLER: And, frankly, that could 8 probably be deferred into the other pending cases we have. 9 MR. FELL: We can be prepared in the other 10 pending cases to answer that. 11 COMMISSIONER MILLER: I don't think it will 12 materially affect the outcome of this case; so why don't we 13 just plan on taking that up again in that next case. 14 MR. FELL: Very well. 15 COMMISSIONER MILLER: All right. 16 MR. FELL: No further questions. 17 COMMISSIONER MILLER: Mr. Weaver, thank you 18 very much for your help. Can this witness be excused? 19 You're free to go or stay as you wish. 20 THE WITNESS: Thank you. 21 (The witness left the stand.) 22 COMMISSIONER MILLER: Let's go off the record 23 for just a minute. 24 (Off the record discussion.) 25 COMMISSIONER MILLER: We will adjourn for the 413 CSB REPORTING WEAVER (Com) Wilder, Idaho 83676 PacifiCorp 1 day and start at 9:00 o'clock in the morning to give 2 ourselves a running jump at it. 3 (The Hearing recessed at 3:45 p.m.) 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 414 CSB REPORTING COLLOQUY Wilder, Idaho 83676