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HomeMy WebLinkAboutPuc8282.v1.doc 1 BOISE, IDAHO, TUESDAY, AUGUST 28, 2001, 1:30 P. M. 2 3 4 COMMISSIONER KJELLANDER: Well, welcome 5 back. We'll go back on to the record and before we 6 adjourned for lunch, I believe Mr. Anderson was still on 7 the stand and you're back. Remember that you're sworn in 8 and it's good to see you and it's our turn now as 9 Commissioners to ask you questions before we move to 10 redirect, so are there questions of members of the 11 Commission? 12 Commissioner Smith. 13 COMMISSIONER SMITH: Thank you, 14 Mr. Chairman. 15 16 DARREL T. ANDERSON, 17 produced as a witness at the instance of the Idaho Power 18 Company, having been previously duly sworn, resumed the 19 stand and was further examined and testified as follows: 20 21 EXAMINATION 22 23 BY COMMISSIONER SMITH: 24 Q I have great notes if I could just read 25 them. Mr. Anderson, in response to questions that were 170 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 asked of you earlier, you stated you have independent 2 sources for your expectation of what the water year is 3 going to be and what the snowpack is? 4 A That's correct. 5 Q What were your independent sources? 6 A Let me get the actual name. It's the 7 National Weather -- no, there's a water bureau that we rely 8 upon where we get the independent information from it. I 9 don't know the exact name of that source, but I can get 10 that, but I don't know the exact name of it. It's the 11 independent source. 12 Q And how frequently do you update or do you 13 know how frequently they update and then how frequently you 14 go back to them and ask them for their updated views? 15 A I do not know the frequency in which they 16 update that information. That's done by our power supply 17 folks and so I don't know the frequency. 18 MR. RIPLEY: Excuse me, Madam Chair, we could 19 supply that name now if you desire. 20 COMMISSIONER SMITH: Okay. 21 MR. SAID: The National Weather Service River 22 Forecast Center. 23 COMMISSIONER SMITH: Thank you. 24 Q BY COMMISSIONER SMITH: Okay, so just bear 25 with me a minute because I'm trying to figure out this and 171 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 I got confused, so I'm trying to get myself unconfused. So 2 in '96 the Company started this RMC to focus mainly on the 3 unregulated side of the business; is that correct? 4 A That's correct. 5 Q And then somewhere along the way you decided, 6 well, maybe we ought to do this for the regulated side of 7 the business? 8 A Correct. 9 Q And do you know about when that was? 10 A That was around 1999 is when that process, is 11 when the considerations beginning to look at the 12 operational data by using some of the expertise that was 13 there that was being -- that was coming in, some of the new 14 talent that was coming in, to begin looking at how we might 15 better manage the system resources. 16 Q Okay, and in '99 when you started doing that, 17 was it just one group? 18 A Yes, there was one Risk Management Committee 19 at that time. 20 Q So then we had all this bumping off? 21 A Well, I'd like to clarify that, actually, 22 because that is something that I don't think was probably 23 characterized correctly. What we did was take a look at 24 the Risk Management Committee, No. 1, coincidentally with 25 the move-out of IDACORP Energy. At the same time that they 172 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 moved out, it was believed that we need to have an 2 independent Risk Management Committee group at that time. 3 Q When did IDACORP move out? 4 A Officially for the Company's books in June. 5 Q Of? 6 A 2001. 7 Q Okay, so all that happened after November? 8 A That's correct. 9 Q So if I'm in November, I'm still with the one 10 group? 11 A Correct. 12 Q No one has been bumped off? 13 A Correct. 14 Q And no committees have been broken up? 15 A Correct. 16 Q All right, and you were the chairman? 17 A And I was the chair person, that's correct. 18 Q Which you probably now regret. 19 A To be honest with you, I don't. It's a great 20 opportunity, so I have to say no, I don't because it is a 21 great opportunity for myself. 22 Q And so this committee was looking at big 23 issues going forward as opposed to the operators who were 24 authorized to do some kind of procurement, which I think I 25 got as the current month plus something. 173 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 A The prompt month, which is the current month 2 that we're in and then the next month is the prompt month. 3 Q Prompt? 4 A Prompt, p-r-o-m-p-t. 5 Q Okay, that's what I was missing. 6 A Okay. 7 Q So on November 21st what the operators could 8 have done is anything in November and anything in December? 9 A Correct. 10 Q But they couldn't have gone into January? 11 A That's correct. 12 Q All right. 13 A So likewise, in December, they can do 14 transactions in December and also for January. 15 Q Okay, and the prompt -- I mean, the months 16 start, like, on the first, it's not like a -- 17 A Right. 18 Q -- rolling time period? 19 A Right. 20 Q All right. Now, I guess another point of my 21 confusion, if we're in the one group and they are doing 22 both the unregulated side and the regulated, it seemed to 23 me that based on your description of their function for the 24 nonregulated side that they would be looking at market 25 information. 174 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 A Let me -- 2 Q Let me finish my question and then we'll see 3 whatever else it is you want to add. 4 A Okay. 5 Q So is that correct? 6 A There's no question they have access to 7 market data. In their world, in the non-op side, they're 8 dealing in the market every day. 9 Q Okay, these are the same people that are 10 doing the regulated side, I assume in the same meetings, so 11 are they told to blank their minds of all market 12 information when they think about the regulated side of the 13 Company? 14 A Let me take a minute to explain the 15 composition of the Risk Management Committee because I 16 think that will help you. Not every one on that committee 17 is in the market every day. 18 Q Right. 19 A The committee is comprised of the officers, 20 basically the senior officers, of the organization: Jan 21 Packwood, the CEO; LaMont Keen, the CFO; Rich Riazzi who is 22 the vice president, at that time was the senior vice 23 president, of marketing and generation who that was job his 24 to be in that marketplace. You had John Prescott who 25 worked on the power supply side; Randy Hill who was at 175 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 Ida-West; Jim Miller who is head of our delivery group; and 2 then myself and Bob Stahman who is out of our legal field, 3 and so not every one of those members are in the market and 4 focused on the market every day. It's really only Rich 5 Riazzi who brings in that marketing piece. 6 Q Right; so he would brief the rest of the 7 group or bring that information? 8 A Right, that data would be available through 9 Rich and some of the folks in his group that attended the 10 meetings. 11 Q On both the regulated and the unregulated 12 side? 13 A That's correct. 14 Q All right; so here we are sitting in November 15 and my recollection is that the prices -- the market went 16 crazy in June of 2000. 17 A That's right. There was a significant spike 18 in June. 19 Q And how long did it last? 20 A I'd have to look at the curve, but I believe 21 it spiked up and then came back down and I'd have to look 22 at the curve, but I think it came down from the historic 23 June prices, from those astronomical June prices. 24 Q After it went up in June, did it ever come 25 back to what we historically thought of as normal? 176 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 A I guess depending on what your definition of 2 normal is, it did -- 3 Q What it had been the previous five years. 4 A I don't believe so. 5 Q Okay; so we're in November, the market went 6 crazy, it never came back down, but if I understood your 7 testimony earlier, you're saying that the risk management 8 function for the regulated side didn't consider market 9 prices when it decided whether to do this deal or not. 10 A I said that one of the considerations was 11 market price, but the main emphasis is first taking a look 12 at what the system requirements are, what the system 13 position is. 14 Q So that was just kind of an aside? 15 A I won't say it was an aside either because 16 obviously there are financial implications to these 17 transactions and if you enter into a transaction, there are 18 going to be monetary requirements to fund those purchases, 19 no question. Price has to be a consideration, but is it a 20 primary driver, no. 21 Q How much of a consideration and how much in 22 the discussion was the fact that 90 percent of these costs 23 are going to get run through the PCA? 24 A To that particular point, the focus of that 25 group when we are talking the operating side, it is focused 177 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 on the operating side and I think it's important to note 2 that there is a -- 3 Q Now, I'm sorry, you're confusing me now 4 because I thought the operators were the people who could 5 do the current month and the prompt month. 6 A Well, that is the operators. I'm talking 7 about the operating side of the business versus the 8 non-operating side of the business. 9 Q When you say "operating side of the 10 business," do you mean the regulated side? 11 A Yes, right, and I think it's important to 12 note that the incentive part of that under the PCA that was 13 discussed earlier, that is a consideration because that 14 does have a negative impact on the Company, the piece that 15 is not absorbed by the PCA, so there is a lot of 16 consideration given to what impact do these decisions have 17 on the PCA, because not only the impact to the ratepayer 18 but also to the shareholder because of that impact. 19 It is fair to say that the impact of the PCA 20 mechanism, while it has been significant to the ratepayer 21 that we know of because we have 168 million, what we also 22 know is that the shareholder has also absorbed more money 23 in 2001 than they have earned at the utility level, so the 24 impact of that absorption, of that piece that they have to 25 absorb, is greater than the amount that the Company has 178 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 actually earned this year. 2 Q But what the shareholder sees is not just 3 from the regulated side; right? 4 A That's correct, no question. 5 Q So there could be a trade-off there. You 6 might take a little hit in the PCA, but we're going to make 7 lots of money on the other side. 8 A One could come to that conclusion. 9 Q Okay. I guess it also comes down to the fact 10 of the note keeping and let me just clarify what I think I 11 understand. On page 5, those additional factors that you 12 outline in A, B, C, those are not in the minutes? 13 A That's correct. 14 Q Okay. If you're stuck in my position, which 15 is to review this after the fact, don't you think you 16 should be entitled to rely upon the writing? 17 A I think that you should be entitled to rely 18 on what actions took place. I don't disagree that writing 19 should help support that, but I also believe that the 20 actions should drive what the ultimate decision is. The 21 recordkeeping aspect of this, in my opinion, doesn't drive 22 what the ultimate decision was, and I guess what I'd like 23 to do, if I could, is kind of put you into the Risk 24 Management Committee meeting on that date of the 21st 25 because I think it's important to understand those 179 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 factors. We've talked a little bit about those today, but 2 I think what's important to note is there was a decision 3 that was made based on the best available information at 4 that time and subsequent to that things changed. It could 5 have been positive, could have been negative, but the 6 issue, I think, is what decision was made at that time 7 based on the data and was that decision right or wrong, and 8 I think it's difficult to go back and take a hindsight look 9 at that decision as to whether or not it was the 10 appropriate decision or not, but was it the decision based 11 on the best available data at that time and I think the 12 actions of the committee are such that a hedge was not 13 requested at the time because the committee did elect not 14 to do that transaction, and if we go back to that meeting, 15 the operations plan, which is based on all the best data 16 available at the time, indicated for the system as a whole 17 that we were net long for the system upwards of 1,300 18 megawatts. 19 Q But not in January? 20 A Not in January; however, the 63 megawatts 21 that were we short was an amount that because we are a 22 hydro system, because of the fact that from a precipitation 23 standpoint we did not know what precipitation was going to 24 be and we were on course to be normal, the 63 megawatts is 25 less than three percent of our generation, less than three 180 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 percent of our load for that month. 2 Q When was your next meeting? 3 A Our next meeting was early December, 4 December 4th, I believe. I think there was a meeting at 5 that point, a special meeting that was held at which point 6 in time at that meeting we discussed the first 7 quarter/third quarter transaction that is referred to in my 8 testimony. 9 Q And did the streamflow forecast change? 10 A The net short position, my recollection is, 11 was approximately the same, actually might have improved a 12 little bit, but the overall length in the system continued 13 to be there and so from an overall portfolio perspective, 14 the system was still long and substantially at that point. 15 Q Well, I guess in my experience, and I don't 16 know about yours, sometimes even clerical errors can be 17 very expensive. 18 A I understand that. 19 COMMISSIONER SMITH: Thank you. Thank you, 20 Mr. Chairman. 21 COMMISSIONER KJELLANDER: 22 Commissioner Hansen. 23 24 25 181 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 EXAMINATION 2 3 BY COMMISSIONER HANSEN: 4 Q Mr. Anderson, I want to follow up just on 5 where Mr. Richardson probably left off. When your 6 committee meets, do you approve the previous meeting's 7 minutes as a group? 8 A We do not. We have instituted that going 9 forward. 10 Q But during this period of time did you have 11 any way or method that the members of that committee sees 12 the minutes or were you the only one that was privileged to 13 see the minutes? 14 A I kept the minutes and they were available to 15 anybody on the committee that requested copies of those or 16 wanted to look at them. 17 Q Are you aware of anyone that requested copies 18 of the minutes of November to look at them besides 19 yourself? 20 A Nobody requested minutes of the November 21 meeting. 22 Q Do you find that in most of these meetings 23 you had in the past no one ever looked at the minutes 24 besides you who wrote the minutes? 25 A There were times when people would request, 182 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 but it was infrequent. 2 Q Okay, a couple of questions on your 3 testimony. On page 5, line 15, and I know 4 Commissioner Smith has just talked to you a little bit 5 about it and maybe I missed it, but can you tell me what is 6 adequate length overall for the system, what is it? 7 A I can't give you a number as to what adequate 8 length is, but it was determined that given where we were 9 at that point in time that 1,300 megawatts appeared to be 10 adequate at that time given our current forecast of 11 precipitation and water. 12 Q On page 8, lines 24 and 25, and I'm just a 13 little confused with your statement there and maybe I just 14 need to clarify it in regards to the Staff's questions, but 15 is it correct to say the Company was not proactive in 16 hedging system requirements to benefit the Idaho Power 17 regulated customers, say, from October through March of 18 2001? 19 A I would say that the Company continued to be 20 proactive in its duties to look at the system overall and 21 manage it most effectively. 22 Q But was that in the interests of the 23 regulated customer? 24 A The focus of the system was for the regulated 25 customer. 183 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 Q So how exactly has the Company been 2 proactive, then, during that time for the regulated 3 customer? What have you done? 4 A I think it's been well documented that the 5 Company has taken a number of actions once it determined 6 that hydro conditions were such that the 2001 water year 7 was going to be as bad -- first of all, no one imagined it 8 would be as bad as it is, but given what some of the early 9 indicators were in January and February, the Company ended 10 up taking proactive measures and taking a look at both 11 demand side reductions as well as adding resources in order 12 to balance out the portfolio once it was recognized that 13 the water was not going to be there. 14 Q But that came along about the first of March, 15 didn't it, when you really started with your irrigation 16 programs, your buy-back from Astaris and some of these 17 programs and your promotion in the news media to conserve 18 and all that, wasn't that along in the end of February or 19 March? I mean, what I'm asking is what did the Company do 20 in November, December and January that shows that they were 21 proactive in this risk management? 22 A In November, December and January as the 23 Company monitored its positions, as the Company determined 24 what the overall length in the system was going to be, in 25 November, it did not indicate that it was going to be 184 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 abnormally short. December still did not indicate that 2 until later in the month when precipitation began to still 3 not show up and so the overall length of the system still 4 did not indicate that those things were going to happen, 5 plus there was still a high likelihood that precipitation 6 was going to come. 7 There have been a number of situations in the 8 Company's past where precipitation has come as late as 9 April that has indicated where water would be greater than 10 or above normal overall snowpacks, so there are 11 variabilities around the weather that somewhat create some 12 challenges for the organization to try and manage that any 13 more proactive. We could have ended up in a situation 14 where we ended up going way long and at the same time the 15 water would come with the potential to have increased 16 additional resources without regard -- and then what do we 17 do with those additional resources at that point in time. 18 In hindsight, we could have sold them into the market and 19 the market was very strong, but at the time we were making 20 those decisions, the water had not come and we were still 21 trying to factor in what those opportunities would be, and 22 as early as February is when we began proactively looking 23 at those demand side and supply side opportunities. 24 Q I understand and can appreciate what you 25 said, but basically, then, you are in agreement that in the 185 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 months of November, December and January you really can't 2 identify anything proactively that you did to help the risk 3 of the regulated customer. You're saying it was towards 4 the end of February when you finally realized that there 5 may be some areas that you should be looking at to help the 6 regulated side; is that correct? 7 A We actively managed the system and monitored 8 the surplus deficits all the way through November, December 9 and January. 10 Q Well, can you identify for me some of those 11 benefits? Did you tie up some long-term contracts? What 12 did you do that actually benefited the customer and can you 13 identify that, quantify exactly what it was? 14 A We did not take any specific actions during 15 those periods of time. What we did, we did monitor the 16 volumes. 17 Q Okay. I guess a question I'd have is why 18 didn't IDACORP devote more attention to protecting the 19 regulated customer from price risk during that time, and if 20 you'd turn to Exhibit 16, Attachment No. 1, it explains 21 there to me when risk management, things that should be 22 handled on risk management. If you'd to turn Exhibit 16 23 and I believe it's 2- or 2.1.7 -- 24 A Larry, do you have a copy of that? I don't 25 have a copy here. 186 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 MR. RIPLEY: Yes, I do. Could we have just a 2 moment? 3 COMMISSIONER HANSEN: Okay. 4 (Mr. Ripley approached the witness.) 5 Q BY COMMISSIONER HANSEN: It would be page 3 6 there at the top of the page on Exhibit 16, 2.1.7. 7 A Larry, I don't think this is the same. On 8 page 3? 9 Q On page 3 of Exhibit 1 -- not exhibit, 10 Attachment 1, I'm sorry. 11 COMMISSIONER SMITH: Page 9 of 13. 12 MR. RIPLEY: In the lower right-hand corner 13 are the page numbers, Commissioner. 14 Q BY COMMISSIONER HANSEN: The lower right-hand 15 corner has Exhibit No. 1 [sic]. It has the Case No. 7/11 16 and it has page 9 of 13 and at the top it has 2.1.7. It 17 says "Risk Management" underlined. 18 A I'm not even sure I'm in the right place 19 because I don't think I am. Exhibit 1 of whose testimony? 20 MR. RIPLEY: No, Exhibit 16. That's 21 Exhibit 16, Mr. Commissioner. 22 THE WITNESS: Okay. 23 MR. RIPLEY: I believe the witness has that. 24 THE WITNESS: And I think in response to your 25 question -- 187 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 Q BY COMMISSIONER HANSEN: Well, I believe I 2 was just referring to it. To that question, I'd like to 3 ask you if you would say this describes the 4 responsibilities of risk management under this agreement, 5 proposed agreement. 6 A Yes, I do, I agree. 7 Q So as you look at some of those and it 8 identifies price volatility and different areas there, when 9 do you think the Company planned on implementing this risk 10 management program? Were you waiting until it was finally 11 approved by FERC and the Oregon Commission or whatever, 12 because you just told me earlier that you really hadn't put 13 a lot of this into effect yet? 14 A No, I think my response indicated that we 15 have spent the time looking at this. What we did not do 16 during that period of time that you referred to is take any 17 specific actions related to those months that you were 18 talking about. There is evidence where we have entered 19 into other hedge transactions to hedge the system at the 20 time it was determined it was appropriate to do so, and so 21 I think it is -- we have been following risk management 22 practices. As it relates to some of those areas that we're 23 talking about, counterparty credit risk, foreign currency 24 fluctuations, some of those things I don't believe are 25 appropriate in light of what we have just been discussing, 188 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 but as it relates to oversight of the process for the 2 system, I do believe that we have been exercising that 3 judgment in the Risk Management Committee meetings related 4 to the operating transactions of the system. 5 Q Mr. Anderson, it says there that the risk 6 management will provide a full-time IES staff that will 7 identify the sources of exposure, so who is that person? 8 A We have a couple of representatives from IE 9 that joined this group. There's an individual named Ajay 10 Sood that isn't on the committee but attends the meetings 11 on behalf of IDACORP Energy. 12 Q And were they doing that in November? 13 A Ajay attended the majority of the meetings 14 and I believe he was there at the November meeting. I'd 15 have to check the list of attendees, but I believe he was 16 there. 17 Q Okay, and so you believe, then, that you were 18 following this where at the last sentence it says, "Risks 19 to be managed include power prices, volatility, interest 20 rates," so forth, so you believe, then, that you were 21 following this right to the letter? 22 A I believe that we were managing the system as 23 it relates to -- in order to balancing the system 24 appropriately, factoring in these other issues, whether 25 they're volatility in prices, but those weren't the key 189 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 drivers to how we managed the system. 2 Q Okay. Back on page 9 of your testimony, 3 lines 17 through 21, I'll give you a minute to get back to 4 that. 5 A Okay. 6 Q Aren't you in effect saying here that you 7 decided it might be quite costly to hedge? 8 A One of the considerations, as I've mentioned 9 before, one of the things that were looked at in November 10 was the fact that we saw prices that were six to ten times 11 higher than any historical amounts had been before and so 12 there was some consideration at that time is that the 13 appropriate time to enter that hedge, but the key driver to 14 the decision wasn't the price. It was considered, but at 15 the same time the key driver was we're 1,300 megawatts 16 long. If prices go up, the system is going to benefit 17 because you are already long, so to the extent that we can 18 manage the system to as flat as we can, then by going 19 longer would just put additional risk on potential price 20 movements and we're trying not to focus on price. We're 21 trying to leave the speculative nature of that business to 22 the nonregulated side of the business, so to go longer in 23 January we believe all it does is put more eggs in your 24 long basket, so by not doing that, that still flattens out 25 the portfolio. 190 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 Q Do you feel that where you had a PCA that 2 allowed the pass-through of costs you really didn't need to 3 put that much emphasis on it, then? 4 A I think the PCA is a mechanism that helps 5 alleviate some of that, but that is not the primary driver 6 to these decisions. The primary driver is how can we 7 minimize the impact to the system. I mean, the PCA is a 8 mechanism in which to collect some of those costs, but 9 there is an impact to the shareholder in that particular 10 situation, also, so the focus is how do we maximize the 11 system and to say the PCA is a mechanism in which to cover 12 those costs, that is a true statement, but it's not a 13 driver to what decisions we make related to whether we 14 purchase or not. 15 Q Well, kind of going through this, do you 16 sense confusion here between the interests of IDACORP and 17 Idaho Power? 18 A I can emphatically say no, and I say that 19 because in our meetings when we are focused on Idaho Power, 20 we are focused on Idaho Power. There's not a decision that 21 says, well, if we make a decision for Idaho Power, what's 22 the impact on the nonregulated side. That is not the way 23 that group works and I can only say that here and you have 24 to trust that what I'm saying is how it happens, because 25 you've got the officers of the organization that are 191 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 committed to this group, so when we're focusing on Idaho 2 Power, we're focusing on Idaho Power without regard to what 3 is going on in the nonregulated side of our business. 4 Q I guess one other question. You talk a lot 5 about your decision based on the shortage of water and yet, 6 really, when you look at it, this huge amount, the 220 7 million, most of that's a result of price volatility, not 8 water; isn't that correct? Really, isn't the major 9 emphasis here that really caught the ratepayer, isn't that 10 the result of skyrocketing prices? I mean, you've had 11 years when you've had bad water years before and you've 12 managed through that and not even come close to this kind 13 of magnitude of rate adjustments, so I guess my question 14 is, really, shouldn't you have been looking a lot more at 15 price, because you've been through the poor water years 16 before and you haven't had this kind of a pass-through to 17 the ratepayers and so by just more or less looking as you 18 had in the past, really, have you let this sneak up and 19 grab the ratepayers where you weren't really looking out 20 for this risk? 21 A If we had the ability to truly be able to 22 forecast prices, I would say you're correct, but in the 23 event that we cannot forecast prices, they can go up and 24 they can go down. We don't believe that we are in the 25 speculative business. We need to manage the resource. If 192 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 we start trying to guess prices, I think 50 percent of the 2 time you're going to be wrong and so, therefore, we have to 3 focus on what does the portfolio of the system have and try 4 to manage to that, manage the reliability, make sure we 5 have the energy there in which to meet the customer's 6 needs. Yes, price has to be a factor, but if we start 7 getting into the guessing game on prices, then I think we 8 become a regulated trading shop which I don't believe is 9 our intent. 10 Q Well, I hear what you're saying and I heard 11 you indicate earlier that price wasn't a key factor in 12 managing the risk. In fact, you even said, I believe, I 13 quoted, price is not a primary driver. 14 A Uh-huh. 15 Q And yet, in this case it's hard for me to 16 believe it's not a primary driver and I guess in your mind, 17 would it be more of a factor if there were no PCA and the 18 automatic cost recovery takes a lot of the sting out of 19 this, does it not? 20 A It does help mitigate the price, there's no 21 question about that, but I think I guess from my 22 perspective on that is what we are trying to do is take a 23 look at what requirements is the system going to need. Had 24 precipitation showed up, I don't believe we would have been 25 in the market and we would have had to pay those prices and 193 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 so the issue is you indicated, well, it's a price issue, it 2 is a precipitation issue. Had water come, I don't believe 3 we would have been in the market. 4 COMMISSIONER HANSEN: That's all I have. 5 COMMISSIONER KJELLANDER: Commissioner Smith, 6 you had a follow-up question? 7 COMMISSIONER SMITH: I just had one 8 clarification. 9 10 EXAMINATION 11 12 BY COMMISSIONER SMITH: 13 Q If you could look at page 6 of your 14 testimony, you have a sentence that begins on line 17 and 15 on lines 18 and 19 there are the words "to the overall 16 results" and on 21 "to the organization." Could you 17 clarify for me which entity you were talking about with 18 regard to "overall results" and what did you mean by "the 19 organization"? 20 A In all those cases those references are to 21 Idaho Power Company and in those cases it reflects the 22 impact it would have on the regulated entity. 23 Q And not to IDACORP or the overall earnings? 24 A Yeah, there is no reference to IDACORP in 25 that statement. 194 CSB REPORTING ANDERSON (Com) Wilder, Idaho 83676 Idaho Power Company 1 COMMISSIONER SMITH: Thank you. 2 COMMISSIONER KJELLANDER: Thank you. We're 3 ready now for redirect. 4 5 REDIRECT EXAMINATION 6 7 BY MR. RIPLEY: 8 Q Mr. Anderson, was there one or two meetings 9 to discuss the November transaction? 10 A All of the discussions related to the 11 November transaction were focused in one meeting. 12 Q And what was the purpose of the minutes? Why 13 did you keep minutes of the RMC? 14 A The primary focus of the minutes was to 15 document activities and discussions that took place for 16 later reference in the event that issues would come up 17 subsequent to the meeting to clarify activities that 18 occurred. 19 Q Was there any regulatory requirement or any 20 business requirement that you knew of as to why you were 21 required to take any minutes? 22 A We're aware of no legal, regulatory or other 23 requirements to maintain minutes for these meetings other 24 than for our own corporate uses. 25 Q And was the creation of the RMC in 1996 195 CSB REPORTING ANDERSON (Di) Wilder, Idaho 83676 Idaho Power Company 1 directly related to the fact that Idaho Power Company was 2 going to engage in trading activities which were not 3 regulated? 4 A That was the original intent of the formation 5 of the committee. 6 Q Was the management of IDACORP concerned with 7 the risks and the financial exposure that could occur from 8 trading activities? 9 A The management of the organization had heard 10 a number of horror stories regarding rogue traders and what 11 have you related to trading operations and it was advised 12 that those procedures needed to be put in place for that 13 organization if they were going to go into the speculative 14 trading arena. 15 Q So RMC was created in 1996 to monitor the 16 trading activities of the nonregulated side of the house? 17 A That's correct. 18 Q We refer to that in these proceedings as the 19 non-op side; is that correct? 20 A That's correct. 21 Q Now, then proceeding forward, I assume that 22 from 1996 to 1999 the industry as a whole became more 23 acquainted with the fact that the wholesale market was 24 opening up? 25 A Correct. Deregulation became to be much more 196 CSB REPORTING ANDERSON (Di) Wilder, Idaho 83676 Idaho Power Company 1 of an issue, therefore, markets began to open up. 2 Electrons started to flow more freely. 3 Q And FERC as the entity regulating wholesale 4 prices was opening up the purchase and sale of that type of 5 energy? 6 A Correct. 7 Q And as a result of that, was it important 8 that Idaho Power Company get up to speed as to what the new 9 activities were in reference to the wholesale market price? 10 A The Company believed it was very important to 11 begin transferring some of that knowledge and using some of 12 that expertise to focus on the regulated side of the 13 business to better manage that system. 14 Q So was that an evolving process of going from 15 the traditional regulated activities in the wholesale to 16 the more and more market-type activity of the wholesale 17 operation? 18 A We believe that it is an evolving process. 19 Continuous improvements continue to happen in that process 20 from the development of our operations plan, implementation 21 of our operations plan and taking a look at better ways to 22 manage the system. 23 Q And since IDACORP had individuals available 24 such as Randy Hill, did it make sense to utilize the 25 expertise of those individuals during this transition or 197 CSB REPORTING ANDERSON (Di) Wilder, Idaho 83676 Idaho Power Company 1 evolutionary time? 2 A I think the thought process was such that we 3 had a lot of expertise there to see if we can't harness 4 that expertise to maximize the benefit. 5 Q Now, directing our attention solely to what 6 we'll call the op side or the utility side of the house, 7 what was the function of the RMC committee toward the op or 8 the utility side of the house, what was perceived to be the 9 function of the RMC committee? 10 A The primary focus of the Risk Management 11 Committee related to the utility side of the business was 12 to take a look at the operations plan and review the 13 operations plan, review the assumptions that are in the 14 operations plan, challenge the assumptions that are in the 15 operations plan and determine what actions, if any, would 16 be in the best interests of the system. 17 Q Now, when you say "the best interests of the 18 system," was the overriding goal to create the situation 19 where the regulated side of the house had sufficient 20 quantities of power to meet its loads? 21 A The focus was to ensure that there was 22 adequate resources from a reliability standpoint in trying 23 to manage the least cost of what that resource is. Least 24 cost doesn't necessarily mean it could be the most 25 efficient way to do it, though, either and so there was 198 CSB REPORTING ANDERSON (Di) Wilder, Idaho 83676 Idaho Power Company 1 that trade-off between the least cost and what is best for 2 the system. 3 Q Now, going back to November of 1999, what we 4 will call the November transaction, please describe for me 5 the circumstances and the information that the committee 6 had available at the time it made its decision concerning 7 the November transaction. 8 COMMISSIONER SMITH: Mr. Ripley, did you 9 intend to say '99? 10 MR. RIPLEY: Yes, I did. 11 THE WITNESS: I was to going to say I think 12 you meant November 2000. 13 MR. RIPLEY: Thank you. 14 THE WITNESS: The Risk Management Committee 15 considered the operations plan at its November 21st 16 meeting. The operations plan indicated a net long position 17 for the system based on almost normal water conditions. It 18 factored in -- it took a look at the fact that we were 19 sitting in November 21st at approximately less than 20 20 percent of what we would normally be, 20 percent of where 21 precipitation might have been from the standpoint of when 22 it falls, but our forecast still looked to be potentially 23 normal water. 24 They also took a look at the situation that 25 you did have prices that were five, six, ten times higher 199 CSB REPORTING ANDERSON (Di) Wilder, Idaho 83676 Idaho Power Company 1 than any historical prices might have been as they looked 2 at January. They also looked to say that given the 3 flexibility in our hydro system that given the magnitude, 4 the 63 megawatts that the system appeared to be short in 5 January, we had the potential to move water to potentially 6 manage that, assuming it would come; therefore, after much 7 discussion, while the initial decision was yes, we think we 8 should cover that, at the end of the day when we finished 9 that meeting, the decision was, well, you know, let's work 10 a little harder on attempting to manage the system. Let's 11 try to see if we can cover that 63 megawatts and as time 12 goes on, more precipitation may fall, we may be in a better 13 position at that point in time. Overall, we're still very 14 long given the 1,300 megawatts that we were long during 15 that period of time, so subsequently, in that same meeting, 16 it was decided that we would not implement the hedge that 17 we had initially discussed. 18 Q BY MR. RIPLEY: Is that what you would 19 consider a rather heated meeting? Were there different 20 views being espoused by various members of the RMC? 21 A It's fair to say in that meeting given the 22 make-up of that committee that there are a number of heated 23 debates that take place in those meetings because everybody 24 has a position and then it's really -- there's a lot of 25 discussion that takes place and when it all came told at 200 CSB REPORTING ANDERSON (Di) Wilder, Idaho 83676 Idaho Power Company 1 the end, the end result was that the decision to not hedge 2 was probably the most appropriate given our length. 3 Q I understand that, but most certainly, I 4 assume you have attended meetings at the RMC where there's 5 been a vote, the parties have voted and then one of the 6 individuals on the negative side of the vote, if you will, 7 will argue further and change the majority? 8 A There are instances where that has happened 9 where they have pondered it for the balance of the meeting 10 and bring it up later in the meeting and then say, you 11 know, I think the decision may or may not be what we should 12 be doing and brings it up for further discussion and so at 13 that point that has happened. Have we reversed decisions 14 before? We have gone on and reversed them at subsequent 15 meetings, we have done that. 16 Q Is this one of those instances where the 17 original vote was taken and then there was further 18 discussion in the same meeting? 19 A Yes, it was. 20 Q And you failed to record the change in your 21 minutes? 22 A That's correct. In my recordkeeping, I 23 failed to record that change at a later date. 24 Q Now, Commissioner Hansen asked you about 25 Exhibit 16 which is the IES agreement. In November -- 201 CSB REPORTING ANDERSON (Di) Wilder, Idaho 83676 Idaho Power Company 1 well, prior to December 19, 2000, there was only one group 2 that was Idaho Power. The non-op and the op side were all 3 housed together? 4 A Correct. 5 Q So when I look at this agreement, this is the 6 type of agreement that I would need if I were going to 7 separate Idaho Power Company into two camps? 8 A Assuming we had an independent group that was 9 going to be managing or providing that service to us, that 10 would be the requirements that we would have of that group. 11 Q So when I look at 2.1.7 that 12 Commissioner Hansen was asking you about, those are the 13 type of activities that were being conducted by Idaho Power 14 Company in the Risk Management Committee prior to the time 15 that there was the creation of the IES agreement? 16 A Those types of discussions, those types of 17 challenges did take place. 18 Q Now, certainly, it was an evolving process so 19 there could be more done than was done at the time of 20 November? 21 A Correct. 22 Q Now, I want to make sure that we have the 23 time period in effect. At the time of the November 24 transaction, as I understand it, the determination was made 25 that in January the Company was going to be only 63 202 CSB REPORTING ANDERSON (Di) Wilder, Idaho 83676 Idaho Power Company 1 megawatts short? 2 A Correct. 3 Q Is that your testimony? 4 A That's correct. 5 Q Now, is it possible for a load of 63 6 megawatts to move water, if you will, from one period into 7 the next? 8 A Our power supply folks believe that we can 9 move those amounts and more, if necessary, depending on 10 water flows and other requirements that may be related to 11 fish and what have you, that's correct. 12 Q Now, when I say "move water," how do I move 13 water from February into January? 14 A Well, moving water basically is a couple of 15 things. It means releasing more water at the time versus 16 holding that water back at times, depending on other 17 requirements that you might have for flood control and fish 18 issues and what have you. 19 Q So I have a reservoir that's full of water; 20 correct? 21 A Correct. 22 Q And I can decide to release water now or 23 release water later? 24 A Right, within certain parameters. 25 Q In the vernacular of the trade is that called 203 CSB REPORTING ANDERSON (Di) Wilder, Idaho 83676 Idaho Power Company 1 moving water? 2 A That's the term moving water. 3 Q Now, in November the Company did not yet know 4 what the precipitation was going to be like in January and 5 February? 6 A That's correct. The forecast at that point 7 in time was still normal or close to normal. 8 Q And was that taken into consideration in your 9 decision to hold off making a decision, you didn't know yet 10 was precip was going to be? 11 A That was probably one of the key drivers in 12 our decision making process was where we stood as it 13 related to precipitation. 14 Q I have one final question, Mr. Anderson. If 15 indeed the Company was simply influenced by the fact of 16 what do I care, I'm going to pass my costs on through the 17 PCA, wouldn't you go out and just buy it then, why worry? 18 A If we had no regard for the ratepayer, we 19 would just be long every month and never short. 20 MR. RIPLEY: That's all the questions I 21 have. Thank you. 22 COMMISSIONER KJELLANDER: Thank you, 23 Mr. Anderson, and I believe that you can be excused now. 24 THE WITNESS: Thank you. 25 (The witness left the stand.) 204 CSB REPORTING ANDERSON (Di) Wilder, Idaho 83676 Idaho Power Company 1 COMMISSIONER KJELLANDER: Mr. Ripley, your 2 next witness. 3 MR. RIPLEY: Yes, Mr. Anderson can be 4 available. He's going to have minor surgery tomorrow and 5 we're wondering if he can be excused from the hearing. 6 COMMISSIONER KJELLANDER: Without objection, 7 that would be fine. 8 MR. RIPLEY: Thank you. We'd call Ms. Hoyd. 9 10 SHARON G. HOYD, 11 produced as a witness at the instance of the Idaho Power 12 Company, having been first duly sworn, was examined and 13 testified as follows: 14 15 DIRECT EXAMINATION 16 17 BY MR. RIPLEY: 18 Q Would you state your full name for the 19 record, please? 20 A Sharon G. Hoyd. 21 Q And your business address? 22 A 350 North Mitchell. 23 Q And, Ms. Hoyd, did you have cause to be 24 prepared for this proceeding certain direct testimony 25 consisting of 21 pages of prefiled testimony? 205 CSB REPORTING HOYD (Di) Wilder, Idaho 83676 Idaho Power Company 1 A Yes. 2 Q And if I asked you the questions that are set 3 forth on those 21 pages, would your answers be the same 4 today? 5 A Yes. 6 MR. RIPLEY: Ms. Hoyd has no exhibits in her 7 direct, so we would ask that her direct testimony be spread 8 upon the record as if read and would tender her for 9 cross-examination. 10 COMMISSIONER KJELLANDER: Without objection, 11 the direct testimony will be spread across the record. 12 (The following prefiled testimony of 13 Ms. Sharon Hoyd is spread upon the record.) 14 15 16 17 18 19 20 21 22 23 24 25 206 CSB REPORTING HOYD (Di) Wilder, Idaho 83676 Idaho Power Company 1 Q. Please state your name, business address and 2 present occupation. 3 A. My name is Sharon G. Hoyd and my business 4 address is 350 N. Mitchell, Boise, Idaho. I am employed by 5 IDACORP Energy, a subsidiary of IDACORP, as Vice President 6 of Finance. 7 Q. What is your educational background? 8 A. I have a Bachelor's degree in Business 9 Administration and Psychology from Albertson College of 10 Idaho. I have also obtained the Chartered Financial Analyst 11 designation awarded by the Association for Investment 12 Management and Research. In addition I have attended the 13 Public Utilities Executive Course and various other 14 continuing education courses over the course of my career. 15 Q. Would you please outline your business 16 experience with Idaho Power Company? 17 A. I began my career with Idaho Power Company in 18 July, 1984 in a temporary position within the Tax 19 Department. In October, 1984 I was hired into a permanent 20 position as an accountant in Corporate Accounting. In 1986 21 I moved to an accounting position in the Corporate Budgeting 22 Department. In 1991 I was selected for a Business Analyst 23 position in the Financial Services Department and was 24 promoted to Manager of that department in 1992. In 1995 I 25 was one of three managers temporarily assigned to develop a 207 HOYD, DI 1 Idaho Power Company 1 Finance Reorganization Plan and later that year became 2 Controller assigned to the Bulk Power Business Unit. In 3 1997, when the Marketing Department was created, I became 4 Controller of Marketing and Generation. In 1998 I was 5 assigned the Corporate Controller position. I served in 6 that position until summer of 2000 when I moved back to the 7 Marketing Department as General Manager of Merchant 8 Finance. In June of 2001, coinciding with the impending 9 movement of energy trading from Idaho Power, I became Vice 10 President of Finance at IDACORP Energy, IDACORP's energy 11 marketing subsidiary. 12 Q. Please describe the evolution of Idaho 13 Power's trading activity. 14 A. Prior to 1997, Idaho Power's involvement in 15 the wholesale markets was directly related to balancing the 16 Idaho Power system. Temporary surpluses caused primarily 17 by increased water volume or reduced load were sold in the 18 wholesale markets, and temporary deficiencies primarily 19 caused by decreased water or increased load was bought from 20 the wholesale markets to serve our customers. Wholesale 21 market participants primarily included other utilities also 22 seeking to balance their systems, and transactions were 23 made between utilities at agreed upon prices without the 24 benefit of public disclosure to use as a benchmark. During 25 this time the region was generally surplus and market price 208 HOYD, DI 2 Idaho Power Company 1 volatility was minimal. 2 In 1996, the Federal Energy Regulatory 3 Commission (FERC) issued its Orders 888 and 889. These 4 Orders, among other things, required the establishment of 5 wholesale open access to transmission systems. To comply 6 with the requirements set forth from FERC, Idaho Power had 7 to do a great deal of internal restructuring. Transmission 8 planning and control area operations had to be split from 9 the power supply dispatching functions. All market 10 information passed between these groups had to be posted 11 publicly. Additionally, utilities were required to schedule 12 their own transmission use through the public site in the 13 same manner, without preference, as third parties. The 14 changes being implemented as a result of these FERC Orders 15 began to dramatically change the nature of the wholesale 16 electricity markets. Marketers, brokers, commodity dealers 17 and others began buying and selling electricity, expanding 18 by hundreds the number of entities participating in the 19 power markets. These new market participants were not 20 interested in the physical delivery of power for purposes of 21 balancing resources with load but were instead interested in 22 buying and selling contracts for purposes of profiting from 23 market price movement. Another signal of the commoditization 24 of electricity markets was the development of the New York 25 Mercantile Exchange (NYMEX) standardized electricity forward 209 HOYD, DI 3 Idaho Power Company 1 contract which led to market price visibility and the 2 further development of electricity derivative products. 3 As the power markets evolved, Idaho Power 4 management recognized the need to evolve its practices of 5 buying and selling power to competently compete in this new 6 market. Idaho Power began in late 1996 to rebuild its 7 power supply department. Many power supply analysts and 8 dispatchers were given new titles as traders and the Company 9 began the process of transforming its utility power supply 10 operation into a commodity trading operation. This process 11 involved hiring expertise from commodity trading, risk, 12 accounting and other related professions on both a permanent 13 and consulting basis to assist in developing the appropriate 14 processes. Throughout the course of 1997 there were 15 parallel paths progressing. The trading group, while having 16 expertise in the physical flow of power, expanded their 17 knowledge of the financial implications of the market forces 18 at work and the financial derivative products that could be 19 created to supplement the traditional physical commodity. 20 The accounting group was charged with developing risk 21 policies and procedures appropriate for a trading operation 22 and to develop a methodology for tracking the speculative 23 trading transactions separately from the traditional buying 24 and selling of energy for system balancing purposes. 25 Along with the organizational and market 210 HOYD, DI 4 Idaho Power Company 1 changes, Idaho Power changed internal processes related to 2 buying and selling power. In evaluating processes, Idaho 3 Power had three primary considerations: 1) maintain the 4 reliability and efficiency of the utility system, 2) seize 5 market opportunities for commodity trading and 3) maintain 6 the lowest possible cost for achieving 1 and 2. The 7 resulting process designed to achieve these three goals has 8 evolved over the last four years, but the foundation has 9 remained the same. 10 Idaho Power has always maintained one trading 11 floor that is responsible for utility purchases and sales 12 as well as all commodity trading transactions. By having 13 the same traders transact for the utility as well as for 14 the trading entity, Idaho Power's retail customers benefit 15 from the market expertise that a full scale trading 16 operation has to offer. Utility transactions, by their 17 nature, will be occurring within the northwest region only 18 at times when Idaho Power is either surplus or deficit. 19 The current trading operation transacts multiples of the 20 utility volume in the western, southern, northern and 21 eastern regions and is able to use this expertise in 22 managing the utility system. 23 Q. Please describe the evolution of accounting 24 requirements for energy transactions. 25 A. Throughout 1997 and 1998, the accounting 211 HOYD, DI 5 Idaho Power Company 1 industry, strongly encouraged by the Securities Exchange 2 Commission, was proceeding with the development of more 3 stringent accounting rules related to derivative 4 transactions. The Securities Exchange Commission, because 5 of several derivative disasters, started requiring more 6 comprehensive disclosure of market risks from publicly 7 traded companies. This disclosure was required beginning 8 with the 1998 10-K. The Financial Accounting Standards 9 Board (FASB), because of the increased development of 10 derivative products, developed comprehensive accounting 11 requirements designed to make accounting for derivative 12 products and hedging more complete and consistently applied. 13 Also, recognizing the increased risk related to the changes 14 in the electricity industry, primarily the increase in 15 energy trading activities, the FASB had the Emerging Issues 16 Task Force (EITF) promulgate generally accepted accounting 17 principles (GAAP) for distinguishing between the traditional 18 utility business of buying and selling energy for purposes 19 of utility operations and the trading business of buying 20 and selling electricity for the speculative purposes of 21 capturing profit driven from market price movement. 22 Statement of Financial Accounting Standards (SFAS) 133, SFAS 23 138 and EITF 98-10 are the resulting accounting requirements 24 from the FASB's work. EITF 98-10, Accounting for Contracts 25 Involved in Energy Trading and Risk Management Activities, 212 HOYD, DI 6 Idaho Power Company 1 was required to be adopted by fiscal year 1999. SFAS 133, 2 Accounting for Derivative Instruments and Hedging 3 Activities and SFAS 138, Accounting for Certain Derivative 4 Instruments and Certain Hedging Activities (an amendment of 5 FASB Statement No. 133), was required to be adopted by 6 fiscal year 2001. 7 EITF 98-10 was written to give clarification 8 between energy contracts and energy trading contracts for 9 accounting purposes. SFAS 133 and SFAS 138 were written to 10 ensure that all obligations with market price exposure are 11 reflected in the financial statements. Following is a 12 summary of the definitions and requirements of EITF 98-10, 13 SFAS 133 and SFAS 138: 14 1. EITF 98-10 is effective for all fiscal 15 years beginning after December 15, 1998. SFAS 133 (as 16 amended) and SFAS 138 are effective for all fiscal quarters 17 of all fiscal years beginning after June 15, 2000. 18 2. SFAS 133 and 138 address accounting for 19 derivative instruments, including certain derivative 20 instruments embedded in other contracts, and hedging 21 activities. 22 3. SFAS 133 stipulates that derivatives are 23 assets or liabilities and that fair value (mark to market) 24 is the only relevant measure for derivatives. Changes in 25 fair value for derivatives not designated as hedges are 213 HOYD, DI 7 Idaho Power Company 1 recorded in current earnings. The Balance Sheet reflects 2 the current fair value for the asset or liability. Special 3 "hedge" accounting is restricted to only certain items 4 qualifying for fair value, cash flow or foreign currency 5 hedges. 6 4. The definition of "derivative" for SFAS 7 133 purposes broadly defines financial instruments or other 8 contracts as derivatives if they exhibit all three of the 9 following characteristics: 10 A. An underlying and a notional amount 11 or payment provision. An underlying is a price or rate of 12 an asset or liability but not the asset or liability itself 13 (for instance, a specified interest rate, security price, 14 commodity price, index of prices or rates, etc.). A 15 notional amount refers to the number of units specified in 16 a derivative instrument, such as number of megawatt-hours. 17 A payment provision refers to a fixed or determinable 18 settlement if the underlying behaves in a certain way. 19 B. No or minimal initial net 20 investment. 21 C. The contract terms require or 22 permit net settlement (the contract can readily be settled 23 net by a means outside the contract, for instance, a 24 contract that can settle for cash without the actual 25 delivery of electricity). 214 HOYD, DI 8 Idaho Power Company 1 5. EITF 98-10 distinguishes between energy 2 contracts and energy trading contracts. Energy contracts 3 refer to contracts entered into for the purchase or sale of 4 electricity or gas. Energy trading contracts refer to 5 contracts entered into with the objective of generating 6 profits on or from exposure to changes in market prices. 7 The criteria for designating between energy contracts and 8 energy trading contracts is defined in EITF 98-10. 9 6. Under the rules stipulated in EITF 98-10 10 and prior to the adoption of SFAS 133 and SFAS 138, 11 contracts designated as non-trading contracts were to be 12 accounted for in accordance with an entity's existing 13 policies. After the adoption of SFAS 133 and SFAS 138, 14 contracts are to first be evaluated for derivative status 15 using the guidelines provided therein. If a contract is not 16 defined as a derivative under SFAS 133 and SFAS 138, then 17 the energy trading contracts criteria defined in EITF 98-10 18 must be applied. Only if contracts are not defined as 19 derivatives under the SFAS 133 and SFAS 138 criteria and are 20 not defined as energy trading contracts under the EITF 98-10 21 criteria are they to be accounted for under the traditional 22 method of accounting for utility energy contracts. All 23 other contracts must be accounted for using the new methods 24 outlined in SFAS 133, SFAS 138 and EITF 98-10. The 25 traditional method of accounting for utility transactions is 215 HOYD, DI 9 Idaho Power Company 1 referred to as settlement accounting, or, recognizing the 2 revenue or expense in income in the month of settlement. 3 Under settlement accounting there is no balance sheet 4 recognition of these transactions beyond the current months 5 accounts receivable or payable. Therefore, a transaction 6 entered into that encompasses more than the current period 7 (a multi-month or multi-year deal) is only recognized in 8 the financial statements a month at a time as the energy is 9 delivered and subsequently billed. 10 7. All transactions meeting the definition 11 of derivative under SFAS 133 or SFAS 138, or meeting the 12 criteria for energy trading contracts under EITF 98-10 may 13 not be accounted for using settlement accounting. These 14 transactions, with the exception of transactions meeting 15 certain defined hedge criteria, must be marked to market, 16 that is, measured at fair value determined as of the balance 17 sheet date. The resulting gains and losses are reported in 18 the income statement and separately disclosed in the 19 financial statements or footnotes. The largest impact of 20 fair value accounting occurs with multi-period transactions. 21 The change in fair value of the entire transaction (all 22 periods of the transaction) is recorded in current income, 23 with the accumulated market value gain or loss being 24 reflected on the balance sheet. The impact of this is the 25 recording of fluctuating profits and losses of multiple 216 HOYD, DI 10 Idaho Power Company 1 period transactions in the current period. 2 Q. Please describe the changes in accounting for 3 Idaho Power's energy purchases and sales. 4 A. Over the course of 1997 and 1998, Idaho Power 5 expanded the volumes of its trading activity while still 6 continuing to buy and sell for the system needs. During 7 the course of the 1996-1997 PCA audit and the 1997-1998 PCA 8 audit, Idaho Power discussed with the IPUC Staff (Staff) 9 the need to account for the trading activity separately 10 from the utility activity. Staff were concerned that risks 11 associated with commodity trading could potentially be 12 passed through to the ratepayers in the PCA adjustment. 13 During the course of the annual PCA audits, Staff ensured 14 there were no costs related to the trading activity being 15 born by the ratepayer but Staff and interested parties still 16 requested that the transactions be separated. Beginning 17 January, 1999, with the implementation of EITF 98-10, Idaho 18 Power implemented a new accounting policy that separately 19 identified and booked the trading transactions as non- 20 operating activity, no longer included as an element of the 21 PCA calculation. This change in reporting was described in 22 the 1998-1999 PCA Order 28049. Pursuant to that case, Idaho 23 Power also worked with Staff and interested parties to 24 conduct a workshop to further explain and investigate the 25 new accounting implementation. 217 HOYD, DI 11 Idaho Power Company 1 Early in 1999, with the adoption of EITF 2 98-10, the Idaho Power Risk Management Committee (RMC) set 3 forth guidelines for utility transactions between operating 4 and non-operating functions. Those guidelines were 5 discussed in depth along with the new accounting rules at 6 the PCA workshop conducted in 1999. These guidelines were 7 then reaffirmed in July, 2000. Following are the 8 procedures that were established: 9 Classifying transactions: 10 1. Purchases or sales will be classified by 11 the trader at the time of the transaction. The trading 12 group will not assume forward market risk by the operating 13 book. In unique circumstances, management may approve 14 forward transactions at fixed prices for the operating book 15 if operating and market circumstances indicate this to be a 16 prudent decision. Any forward transaction entered into for 17 the system must be documented and signed by the Senior VP 18 of Marketing and Generation and the VP of Finance and 19 Treasurer or two designated alternates from the Risk 20 Management Committee. Forward transactions are defined for 21 this purpose as transactions for any month beyond the 22 prompt month for the system. 23 2. Transactions related to the balancing of 24 system load and system resources and transactions related to 25 system reliability are classified as operating transactions. 218 HOYD, DI 12 Idaho Power Company 1 These transactions are recorded and maintained in an 2 operating book that is separated from other trading 3 transactions. The trading group, under the guidance of the 4 Senior VP of Marketing and Generation, has the authority to 5 enter into these transactions as necessary to prudently 6 manage the utility system beginning one month prior to the 7 settlement month and continuing through the last day of the 8 settlement month. Operating transactions meet the energy 9 contracts definition of the Emerging Issues Task Force 10 consensus opinion. Operating transactions are included for 11 PCA reporting purposes. 12 3. Transactions not related to the 13 balancing of system load and resources are classified as 14 non-operating. These transactions are maintained in 15 non-operating trading books that are differentiated from 16 one another by time periods long-term, intra-month and real 17 time. Non-operating transactions meet the "energy trading 18 contracts" definition of the Emerging Issues Task Force 19 consensus opinion. Non-operating transactions are excluded 20 for PCA reporting purposes. 21 4. Prior to settlement, transactions occur 22 between the operating and non-operating books at the 23 appropriate market settlement price or third party quote in 24 order to start bringing the system into balance at the 25 lowest cost. The market settlement price to use for term 219 HOYD, DI 13 Idaho Power Company 1 and intra-month transfers between the operating and 2 non-operating books will follow the formula detailed below. 3 Any transfers made in real-time will be transacted at the 4 average of all real-time transaction prices entered into on 5 the day in question at the appropriate delivery point and 6 hour. 7 Following is the transfer pricing formula 8 currently and historically used for daily transactions 9 between operating and non-operating. This is the same 10 formula discussed in the 1999 workshop and audited in the 11 1998-1999 PCA case, the 1999-2000 PCA case, and the 12 2000-2001 PCA case. 13 Purchases (using Mid-C Index for intramonth 14 deals, using Mid-C quote for term deals) 15 Transfer Cost = (Mid-CLL x Total LL MWh) + 16 (Mid-CHL x Total HL MWh) + Transmission Cost where 17 'Transmission Cost' is the sum of firm transmission tariff 18 rate of a transmission provider that has available 19 transmission capacity from Mid-C and cost of transmission 20 losses charged by the transmission provider. 21 Sales (using Mid-C Index for intramonth 22 deals, using Mid-C quote for term deals) 23 Transfer Cost = (Mid-CLL price x Total LL MWh) 24 + (Mid-CHL Price x Total HL MWh) - Transmission Cost where 25 'Transmission Cost' is the sum of firm transmission tariff 220 HOYD, DI 14 Idaho Power Company 1 rate of a transmission provider that has available 2 transmission capacity to Mid-C and cost of transmission 3 losses charged by the transmission provider. 4 Purchases (using Palo Verde Index for 5 intramonth deals, using Palo Verde quote for term deals) 6 Transfer Cost = (Palo VerdeLL Price x Total LL 7 MWh) + (Palo VerdeHL Price x Total HL MWh) + Transmission 8 Cost where 'Transmission Cost' is the sum of firm 9 transmission tariff rate of a transmission provider that has 10 available transmission capacity from Palo Verde and cost of 11 transmission losses charged by the transmission provider. 12 Sales (using Palo Verde Index for intramonth 13 deals, using Palo Verde quote for term deals) 14 Transfer Cost = (Palo VerdeLL Price x Total LL 15 MWh) + (Palo VerdeHL Price x Total HL MWh) - Transmission 16 Cost where 'Transmission Cost' is the sum of firm 17 transmission tariff rate of a transmission provider that has 18 available transmission capacity to Palo Verde and cost of 19 transmission losses charged by the transmission provider. 20 The transfer pricing formula applied to real 21 time transactions is also the same as originally defined, 22 however, prior to December, 2000 there were relatively few 23 real time transactions occurring between operating and non- 24 operating. Prior to December, 2000, all real time 25 transactions were classified as operating with the exception 221 HOYD, DI 15 Idaho Power Company 1 of a relatively few closed (offsetting purchase and sale) 2 transactions that could be specifically identified as 3 non-operating. 4 Q. When the Idaho Commission approved the 5 transfer pricing methodology by Order No. 28596 in Case No. 6 IPC-E-00-13, did the Company change its real-time 7 transaction classification process? 8 A. Yes. With the IPUC approval of the 9 Electricity Supply Management Agreement, the Company 10 believed the process needed to change in order to be in 11 compliance with the procedures outlined in the agreement. 12 Our non-operating real-time volumes were increasing rapidly 13 with substantial real time business occurring in the 14 volatile California markets and other markets not relevant 15 to Idaho Power Company's operation. In order to correctly 16 align the credit and market risks of this increasing real 17 time non-operating business and to ensure the real time 18 traders did not have the ability to mis-classify 19 transactions for the benefit of either the operating or 20 non-operating book, the characterization of real time 21 transactions was reversed to classify the majority of the 22 deals as non-operating. The real-time operating business 23 was accounted for by transferring volumes between the 24 operating and non-operating books at the weighted average 25 price of relevant non-operating transactions (real-time 222 HOYD, DI 16 Idaho Power Company 1 transactions occurring at system points). 2 Q. Why did you choose the Mid-C index as the 3 transfer price for daily transactions? 4 A. When determining what the pricing mechanism 5 should be for transactions between operating and 6 non-operating there were several goals. 7 1. The price must be fair to both operating 8 (utility function) and to non-operating (the trading 9 function). 10 2. The price must be a relevant 11 representation of market. 12 3. The price must be able to be 13 consistently applied. 14 4. The price must be insulated from 15 manipulation. 16 5. The price must not transfer risks of the 17 trading operation to the utility function. 18 In meeting these goals the Dow Jones Mid-C 19 index became the obvious choice. Mid-Columbia (Mid-C) is 20 the closest trading hub to the Idaho Power system. The Mid- 21 C hub is widely recognized by market participants as the 22 delivery point in the Northwest most actively traded and 23 most representative of the Northwest market. All northwest 24 market participants transact at Mid-C and often set prices 25 at the Dow Jones Daily Mid-C index. Dow Jones publishes 223 HOYD, DI 17 Idaho Power Company 1 daily commodity price indexes for a variety of commodities 2 at a variety of hubs. Dow Jones chooses the hubs based on 3 volume of business transacted at these locations and the 4 ability to easily trade in and out of positions and has, 5 for some time, published daily Mid-C index prices for the 6 preceding day. 7 By using daily, externally produced, index 8 prices at a liquid market hub, Idaho Power personnel have no 9 ability to manipulate the price. The use of an index from 10 highly liquid market hub published the day after the trading 11 day eliminates any criticism that the trading function might 12 advantage itself through knowledge of the utility system's 13 position. The use of objective market pricing for 14 transactions between affiliates is essential to allow both 15 the customers of the utility and shareholders of the company 16 to feel assured that the relationship between the affiliates 17 is arms length and cannot be manipulated to the unfair 18 benefit of one over the other. 19 Additionally, by using the Mid-C index as the 20 pricing point, the utility is not subject to the volatility 21 of non-operating transactions occurring in other regions. 22 Non-Operating transactions realized volume growth from 1999 23 to 2000 of 68%. Much of this growth was achieved by non- 24 operating activities moving into new regions. There have 25 been non-operating transactions as far east as Iowa, as far 224 HOYD, DI 18 Idaho Power Company 1 north as Alberta and as far south as California and New 2 Mexico. In 2001 the non-operating activity has expanded 3 its geographic presence even more. By moving into new 4 regions, the non-operating system begins taking on new 5 risks, such as additional credit risk and market risk 6 driven by the physical constraints and volatility in those 7 regions. By tying operating/non-operating transfer pricing 8 to the Mid-C index, the operating book is assured of a 9 price based on relevant markets and is not incurring the 10 risks or costs of markets outside of the region. 11 Also, because there are published Mid-C index 12 prices every day, the pricing methodology can be applied 13 consistently. 14 Finally, the operating book and the non- 15 operating book must know the price of the transaction at 16 the time of the transaction. Without this knowledge it is 17 impossible to manage the market risk associated with the 18 transaction. Index priced transactions tied to the Dow 19 Jones Mid-C index are very common in the market place. The 20 commonality of these transactions indicates that they are 21 able to be hedged, meaning a financial transaction can be 22 entered into that will offset the market risk of the index 23 pricing. Without having a visible, liquid market index to 24 price the financial hedge, the market risk is very 25 difficult to mitigate. 225 HOYD, DI 19 Idaho Power Company 1 Q. Why is real-time transfer pricing based on a 2 weighted average pricing methodology? 3 A. In determining the methodology used for 4 real-time transfers, the same criteria applied. 5 1. The price must be fair to both the 6 operating (the utility function) and to non-operating (the 7 trading function). 8 2. The price must be a relevant 9 representation of market. 10 3. The price must be able to be 11 consistently applied. 12 4. The price must be insulated from 13 manipulation. 14 5. The price must not transfer risks of the 15 trading operation to the utility function. 16 Real-time markets do not have the advantage 17 of a published index. Therefore, a transfer price was 18 developed using the weighted average pricing (WAP) of all 19 non-operating deals relevant to the system (utility) market. 20 The WAP is a method that is fair to both the operating and 21 non-operating functions because both are impacted equally 22 by the pricing volatility occurring within an hour. This 23 process cannot be manipulated because all relevant 24 transactions are used for the transfer calculation. Also, 25 by utilizing only those transactions occurring at system 226 HOYD, DI 20 Idaho Power Company 1 points, a relevant representation of the market is created. 2 In this way the operating book is not subject to the risks 3 of price volatility in markets outside the region as 4 trading activity continues to expand. 5 Q. Did Idaho Power use the transfer pricing 6 methodology described above in its calculation of costs 7 included in the April, 2000 through February, 2001 PCA 8 calculation? 9 A. Yes. 10 Q. In your opinion, are the costs included in 11 the PCA filing, Case No. IPC-E-01-11, for the period April, 12 2000 through February, 2001, fair, just and reasonable? 13 A. Yes. 14 Q. Does this conclude your testimony? 15 A. Yes. 16 17 18 19 20 21 22 23 24 25 227 HOYD, DI 21 Idaho Power Company 1 (The following proceedings were had in 2 open hearing.) 3 COMMISSIONER KJELLANDER: And we'll move, 4 then, to cross-examination from the Deputy Attorney General 5 representing Staff. 6 MS. NORDSTROM: Thank you. 7 8 CROSS-EXAMINATION 9 10 BY MS. NORDSTROM: 11 Q Good afternoon. 12 A Hi. 13 Q On page 3 of your direct testimony, lines 22 14 and 23, you state that market participants were interested 15 in buying and selling contracts for purposes of profiting 16 from market price movement; is that correct? 17 A Yes. 18 Q Isn't it true that the non-operational arm of 19 Idaho Power which later became IE is a market participant 20 that buys and sells for the purpose of profiting from 21 market price movement? 22 A The non-op side of the business, the charge 23 for the non-op side of the business is to profit from 24 making transactions looking at market price movement within 25 certain risk parameters. 228 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 Q Would you agree that significant price 2 movement during a particular day provides opportunity for 3 market participants to profit? 4 A Potentially. 5 Q Can a profit be made if a market participant 6 is able to consistently purchase day-ahead energy at a low 7 price and sell at a higher daily Mid-C index? 8 A I think that if a market participant is 9 consistently purchasing and selling power with the idea 10 that they know which direction market prices are going to 11 go that they will consistently profit and lose money. No 12 market participant knows what the market prices are going 13 to be. 14 Q On page 5 of your direct testimony, lines 12 15 through 16, you say that Idaho Power's retail customers 16 benefit from the market expertise that a full scale trading 17 operation has to offer. Would this market expertise 18 include the ability to secure market purchases at a lower 19 price through hedging than would otherwise be paid for 20 day-ahead or real-time purchases? 21 A I think maybe that that's being misread. 22 What Idaho Power's retail customers benefit from in terms 23 of market expertise is looking at potential hedge 24 opportunities and managing risk. Managing risk is not 25 always the same as lowering cost. 229 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 Q But it could have that effect; correct? 2 A It could have the effect of lowering costs. 3 It could have the effect of raising costs if you are 4 choosing to take less risk. 5 Q Would this market expertise also include the 6 ability to secure day-ahead energy at a cost that is below 7 the Mid-C index? 8 A Can you be more specific? Where would we 9 procure the energy, for what purposes? 10 Q Well, presumably, the expertise of a 11 marketing affiliate would be to specialize in market 12 movements in order to try and make a profit and so would 13 this expertise include the ability to secure day-ahead 14 energy at a cost that is lower than the Mid-C index? 15 A Well, as I stated before, there is no market 16 participant that can tell you what prices will be and so 17 to -- if you're implying that our market expertise should 18 provide the opportunity to consistently beat a market 19 price, that's not a true statement and that's not something 20 that we can do or any market participant can do. 21 Q On page 15 you describe the transfer pricing 22 formula that was applied to real-time transactions. Why 23 did so few real-time transactions occur prior to December 24 2000 and significantly more occur after that time? 25 A Can you point to me where you've said I've -- 230 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 what line I've defined real-time transfer pricing formula? 2 Q At lines 20 and 21 you say, "The transfer 3 pricing formula applied to real-time transactions is also 4 the same as originally defined." 5 MR. RIPLEY: I'm sorry, what page are you 6 on? 7 MS. NORDSTROM: Page 15. 8 MR. RIPLEY: 15. 9 THE WITNESS: Okay, can you go on and restate 10 your question, please? 11 Q BY MS. NORDSTROM: Why did so few real-time 12 transactions occur prior to December 2000 and significantly 13 more occur after that time? 14 A I think what is stated here is that prior to 15 December 2000 there were relatively few real-time 16 transactions between the operating and non-operating. 17 Q Okay; so with that clarification, why? 18 A Why is that the case? 19 Q Uh-huh, what changed? 20 A Well, nothing really changed except for how 21 we classified transactions. Beginning -- prior to December 22 2000, all real-time transactions with the exception of some 23 non-operating transactions that we could qualify as a 24 closed purchase and sale off the system, they were 25 classified as operating transactions. Beginning December 231 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 2000 moving forward, that classification changed where they 2 were now classified as non-operating transactions. Because 3 they were now classified as non-operating transactions, the 4 real-time need of the system had to occur between the 5 operating and non-operating books of business. 6 Q What was the purpose of this relatively large 7 change in operating procedure? 8 A Well, the purpose from our standpoint was 9 that it's an evolution of continuing improvement in the 10 procedures of tracking costs and risks appropriate with 11 both the operating side of the business and the 12 non-operating side of the business. 13 Q So in summary, the way you tracked costs 14 changed in December; is that an accurate statement? 15 A Well, in December what we did in our 16 evolution was to take what had been approved in the 17 Commission Order and apply it fully to the operating and 18 non-operating business. 19 Q Directing your attention to page 16, lines 8 20 through 15, you indicate that the Company believed the 21 process needed to change. Why did the Company implement 22 this change before the agreement between Idaho Power and 23 IES went into effect? 24 A Well, there's probably two reasons, I guess. 25 One is we felt like once we had a Commission Order 232 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 approving a practice regardless of whether or not that 2 Order was technically in effect that it was -- our intent 3 was always to fully comply with what the wishes were for 4 these procedures and so that's why we implemented that 5 pricing in December. We also felt like it was the best 6 representation of real-time market prices and the risks 7 associated with the real-time business. 8 Q Was that in part due to the volatility 9 experienced last winter in the market prices? 10 A I would say that it was more reflective of 11 the fact that the non-operating side of the business was 12 more active in the real-time markets that they had 13 previously been. 14 Q What was the purpose of the effective date in 15 the agreement if it wasn't to be followed? 16 A The effective date in what agreement? 17 Q In the Idaho Power/IES service agreement. 18 A And what was the effective date? 19 Q The effective date was when the Idaho, Oregon 20 and FERC commissions approved use of the methodologies 21 described therein. 22 A Well, again, I guess this change in real-time 23 was made to try to continue to evolve our procedures to 24 reflect the best market pricing and risk classification, I 25 guess for lack of a better word, between operating and 233 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 non-operating. 2 Q Okay, on page 16, lines 15 and 16, you state 3 that this real-time pricing change was necessary in order 4 to "correctly align the credit and market risks." How 5 could proper assignment of the risks occur if the 6 non-operating book used the operating system's trading 7 certificate and creditworthiness to make these transactions 8 until IE officially became a separate entity later in 2001? 9 A The alignment of risk was between operating 10 and non-operating. It was all within Idaho Power. It 11 wasn't between Idaho Power and IE. 12 Q But if IE or the non-operating system was 13 using assets of the regulated entity, how was that properly 14 assigning risks? 15 A The risks I'm referring to there are the 16 market risks and credit risks associated with the 17 third-party transactions. Those risks we moved down to the 18 non-operating book of business so that they would not be 19 passed through to the ratepayers of Idaho Power. 20 Q It was my impression that if you used the 21 trading certificate of the regulated utility that the 22 regulated utility was on the hook for paying the bill in 23 the event the non-operating side couldn't do it. 24 A Idaho Power was liable for the risks. Idaho 25 Power's ratepayers were not. 234 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 Q But if in the event that Idaho Power had to 2 cover those costs, that would in essence be detrimental to 3 ratepayers; correct? 4 MR. RIPLEY: Objection. That calls for a 5 legal conclusion of the witness. That question is fraught 6 with a number of legal assumptions. 7 MS. NORDSTROM: Financially that's not. 8 MR. RIPLEY: See, that's the issue. 9 MS. NORDSTROM: Well, she's a finance expert. 10 MR. RIPLEY: I will object on the grounds it 11 calls for a legal conclusion of the witness. 12 COMMISSIONER KJELLANDER: Any response? 13 MS. NORDSTROM: Her area of expertise is 14 finance and specifically that related to the non-operating 15 system. Certainly, she can understand the ramifications of 16 what would happen if someone couldn't pay the bills. 17 That's okay. I'll withdraw the question. 18 Q BY MS. NORDSTROM: Just to clarify some 19 terminology, is it correct to say that term contracts are 20 usually entered into with third parties? 21 A By who? By operating? Non-operating Idaho 22 Power? 23 Q Either. 24 A I guess I'm just still not quite 25 understanding your question. I'm sorry. 235 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 Q During the PCA period did the non-operating 2 system enter into third-party contracts, term contracts? 3 A Yes. I might expand a little bit on that. 4 The non-operating business itself is in the business of 5 buying and selling and buying and selling and buying and 6 selling power, that's what the traders do, so it's not 7 unusual to see, if you choose a month, say October, for 8 example, to see purchases and sales of the October contract 9 multiple times over prior to October. 10 Q Okay. Is it true that Idaho Power and the 11 Risk Management Committee specifically approve term 12 transactions for the system? 13 A Any term transaction entered into for the 14 operating side of the house had to be approved specifically 15 by the management of Idaho Power Company. 16 Q Can these transactions be easily identified? 17 A Easily identified by -- 18 Q Within the books of operating and 19 non-operating? 20 A Yeah, they're very clearly marked. 21 Q Is it true that IDACORP Energy or the 22 non-operating side historically may have brokered term 23 transactions and will broker term transactions in the 24 future? 25 A Yes. 236 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 Q Historically, have term transactions been 2 priced at cost? 3 A Because of the nature of it being brokered, 4 they are priced at the actual transaction cost, yes. 5 Q Is it correct to say that day-ahead 6 transactions are priced at the market index? 7 A Day-ahead transactions are priced at market 8 just as term transactions are priced at market. 9 Q Whereas real-time transactions are priced at 10 the average price for real-time transactions touching the 11 system; is that also correct? 12 A Which is also market for real-time. 13 Q Touching the system is kind of a term of art, 14 how would you describe what it means? 15 A We have the situation between operating and 16 non-operating where the non-operating volumes of business 17 far exceed the volumes of business for the operating 18 system. That business, the volume of business for the 19 non-operating side of the house is transacted all over the 20 western United States, into the Midwest, up into Canada and 21 expanding. What we talk about when we talk about touching 22 the system and the way we've used it is energy that 23 actually comes through intertie points at the Idaho Power 24 borders, Idaho Power control area borders. 25 MS. NORDSTROM: May I approach the witness? 237 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 COMMISSIONER KJELLANDER: Sure. 2 (Ms. Nordstrom approached the witness.) 3 Q BY MS. NORDSTROM: I'm handing you Staff 4 Exhibit No. 132. I've handed copies to -- 5 A This is a new exhibit; is that right? 6 Q Yes, it is. Are you familiar with this 7 document? 8 A With this exhibit? This is really the first 9 I've seen of this exhibit. 10 Q Do you recognize this as a copy of the 11 November summaries you provided to Terri Carlock for review 12 as part of your rebuttal workpapers? 13 A Well, it does look familiar. I haven't had a 14 chance to see if all the numbers are the same as what I 15 provided her or anything else, but I'll assume she 16 correctly copied it. 17 Q Would you like to check right now? 18 A Like I say, I'll just assume she correctly 19 copied it. 20 Q Do you have the underlying workpapers with 21 you as Staff requested? 22 A I think somewhere, not up here. 23 Q Okay, these are the Idaho Power summary 24 sheets for day-ahead November transactions. If you compare 25 the intercompany day-ahead purchases for heavy load hours 238 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 in column 1 of page 1 with the intercompany day-ahead sales 2 for heavy load hours in column 1 of page 2 on the same day, 3 would you see both intercompany sales and purchases shown? 4 A There are both intercompany sales and 5 purchases shown, yes. 6 Q And can you explain why this occurs? 7 A Yes, I can. It's kind of complicated, so if 8 anybody has questions in the explanation, please ask them. 9 Basically what is transpiring in that purchase and sale is 10 effectively a swap transaction between day-ahead prices and 11 real-time prices and the reason this occurs, if I back up 12 and we talk about how the traders trade day-ahead, they 13 are -- for example, if we were to say today is Tuesday, 14 this afternoon the traders are going to look at their 15 forecast for the system for Thursday. 16 They're going to look at projected loads, 17 projected generation. They're going to look at any hedges 18 that have been put in place, any purchases, sales, 19 cogeneration, if there's any fish water that needs to move, 20 any exchanges in place. They're also going to look at what 21 the non-op total position is, whether the non-op side of 22 the business is long or short and that's what they're 23 looking at this afternoon for Thursday. 24 Tomorrow morning, then, they have to come in 25 and they've got about a two-hour window, I would say, from 239 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 about 7:00 to 9:00 where they have to trade that entire 2 position, so they make transactions buying and selling for 3 both operating and non-operating classifying all of those 4 transactions as non-operating for the intent that they are 5 not picking and choosing which transaction is going to 6 supply the system and which transaction is going to supply 7 the non-op side. 8 At the end of the trading day, they relook at 9 that forecast for tomorrow and the forecast can change 10 between yesterday afternoon and this afternoon, so 11 effectively what happens is the traders now look at it and 12 let's just hypothetically take an example. Let's say their 13 non-op position has netted out to zero and the operating 14 forecast has moved and now the operating side of the house 15 is looking like it's going to be short tomorrow by 100 16 megawatts. What the traders were charged with doing was 17 making sure to the best of their ability that the operating 18 system did not go into real-time with any long or short 19 position. 20 The management of our Company didn't want to 21 take any unnecessary real-time risk with the operating side 22 of the business, so basically the traders are now looking 23 at a situation where the operating system looks like it's 24 going to be short tomorrow by 100 megawatts and the only 25 thing that they have left to do at that point is to buy in 240 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 real-time to meet that need; however, they've been asked to 2 not do that, to not go into real-time to meet that 3 day-ahead pre-schedule need. 4 Now, prior to December, we have to remember 5 that all real-time transactions were classified as 6 operating transactions, so the only way for the Company to 7 shift that real-time risk away from operating and into 8 non-operating was to enter into essentially a financial 9 swap of that transaction and so what they did is they took 10 that 100 megawatts short position and they said okay, 11 non-operating, I want to buy that energy from non-operating 12 day-ahead and the price for that is the market price for 13 day-ahead transactions, so they purchased the 100 megawatts 14 day-ahead transactions from the non-operating system. 15 In an exchange for that, because we do have 16 to go into real-time to actually source it physically, we 17 know we'll be buying power in real-time on the operating 18 side, so we're going to sell that power back to 19 non-operating at those real-time prices, so it's 20 essentially a swap transaction where the operating system 21 buys in real-time, sells at the real-time price to 22 non-operating and purchases back from non-operating at the 23 day-ahead price and I can -- I know it's complicated. I 24 can write out boxes for you or I've actually got an exhibit 25 here that explains it a little bit if you guys would like 241 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 to look at that. 2 MR. RIPLEY: Perhaps the exhibit would be 3 helpful. 4 COMMISSIONER KJELLANDER: Anything would be 5 helpful. 6 MR. RIPLEY: Let's take a moment. I haven't 7 seen it either. Do you have copies, Sharon? 8 THE WITNESS: I have a few copies. 9 COMMISSIONER KJELLANDER: While we're at this 10 point in our lives, we'll just take a ten-minute break. 11 (Recess.) 12 COMMISSIONER KJELLANDER: I believe we're 13 ready to go back on the record and right before we 14 adjourned there was a document that was going to be 15 distributed and I believe that we all have that and it was 16 to assist in clarifying some of the transactions and how 17 they were conducted, and I think just to remind me, I think 18 the last words said were that they sell at the day-ahead 19 and they buy at real-time; was that correct? 20 THE WITNESS: Well, maybe I should just go 21 through this. 22 COMMISSIONER KJELLANDER: Now, as I 23 understand it, too, if we go back into sort of where we're 24 at procedurally, weren't we into cross still? 25 COMMISSIONER SMITH: Yes. 242 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 COMMISSIONER KJELLANDER: Correct, okay. 2 COMMISSIONER SMITH: So what is this? 3 MR. RIPLEY: But perhaps for the record if we 4 could identify this as an exhibit and then Ms. Hoyd can 5 speak from it and we'll pass it back to -- 6 COMMISSIONER KJELLANDER: All right, let's do 7 that and get it formally in the record. 8 MR. RIPLEY: All right. Ms. Hoyd, you have 9 mentioned that you have prepared an exhibit. Could you 10 please describe this exhibit that you have prepared as to 11 the number of pages and the titles? Don't go into what it 12 says. 13 THE WITNESS: It's actually six pages long 14 and the headings on the first three columns say, "Non-Op 15 Spreadsheet" or in parentheses "Non-Op trades" and "Column 16 D minus Column B" and then "Casso Total, Control Area, 17 Balancer report." 18 MR. RIPLEY: We would ask that this be marked 19 as Idaho Power Company Exhibit 30 for the record, 20 Mr. Chairman. 21 COMMISSIONER KJELLANDER: So without 22 objection, this would be Exhibit 30 and we'll go ahead and 23 admit it, then, officially as an exhibit. 24 (Idaho Power Company Exhibit No. 30 was 25 admitted into evidence.) 243 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 MR. RIPLEY: I don't know what the Attorney 2 General's privilege is. Does she want the witness to 3 explain the exhibit? 4 MS. NORDSTROM: That's fine. 5 THE WITNESS: Okay, if you turn to the third 6 page in on this -- 7 COMMISSIONER SMITH: Mr. Chairman, I hate to 8 cause trouble, but I have seven pages. 9 THE WITNESS: You do? 10 MR. RIPLEY: You have what? 11 COMMISSIONER KJELLANDER: I also have seven. 12 I'm wondering if there are any duplicates. 13 THE WITNESS: No, there are seven. I'm 14 sorry, I miscounted. I'm an accountant that can't count 15 correctly. 16 COMMISSIONER KJELLANDER: We'll go ahead and 17 strike that comment and I think we'll proceed then with a 18 quick description. 19 MR. RIPLEY: Exhibit 30 consists of seven 20 pages. 21 COMMISSIONER KJELLANDER: Thank you. 22 THE WITNESS: And if you go to the third page 23 in, it describes the situation that we were talking about 24 previously and what I'd like to do is kind of walk everyone 25 down line by line on this exhibit. Now, the first line, 244 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 and actually I guess I'd like to reiterate that even prior 2 to the first line, we're back on Tuesday afternoon again, 3 looking at a forecast for Thursday of the operating system, 4 then we trade on Wednesday morning and then relook at that 5 forecast for Thursday and the day-ahead transaction for the 6 operating system is documented at that point after the 7 day's trading when we relook at the forecast for the next 8 day. 9 In this first line here is a hypothetical 10 example of what might have happened, positions after the 11 day-ahead trading for the next day. The non-op position 12 we'll say was balanced going into real-time. The operating 13 position had a 500 megawatt long position. This means -- 14 COMMISSIONER KJELLANDER: I'm on page 3 and I 15 see 400. 16 THE WITNESS: Under operating position 400, 17 did I not say 400? 18 MR. RIPLEY: You said 500. 19 THE WITNESS: I'm sorry, I meant 400. Thank 20 you for clarifying, so we have a zero non-op position, a 21 400 megawatt operating position in this hypothetical 22 example, so the net Idaho Power position is 400 megawatts 23 that we have to take next day into real-time to sell. The 24 management of this Company, of Idaho Power Company, has 25 said to the trading group they do not want to take a 245 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 position into real-time for Idaho Power's system, so what 2 we've done is we've created a transaction, which is the 3 next shaded area down, between the operating position and 4 the non-operating position where the operating position 5 sold 400 megawatts that it was long to the non-operating 6 position, so what it does on the next line down, net 7 positions, you can see it just shifts that 400 megawatts. 8 Now the non-operating system is long and has to sell its 9 energy in real-time. 10 The net position for Idaho Power Company is 11 still 400 megawatts long, so now we move into real-time and 12 we sell the 400 megawatts, and in this example we're saying 13 basically that we were perfect in our forecast. At that 14 point in time, you know, in real-time we had exactly 400 to 15 sell, there were no changes in real-time to the actual 16 circumstances, so we sell third-party sales in real-time 17 that we were long going into the day. 18 Those transactions prior to December were all 19 classified as operating transactions, so in effect, if we 20 would have just left things alone right there we would have 21 not effected the entire transfer of real-time risk to the 22 non-operating group and we have an imbalance between 23 non-operating and operating. Our non-operating book of 24 business for that day-ahead volume had 400 megawatts long, 25 non-operating sold 400 megawatts in real-time that it 246 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 didn't have, so we created another transaction that 2 basically trued up that energy going into real-time and 3 here's where the operating position now bought back from 4 the non-operating position energy at a real-time price and 5 that real-time price was calculated the next day after all 6 the real-time trading was over. It was an average heavy 7 load price for the heavy load hours and light load price 8 for the light load hours, and you really need to take those 9 two transactions together to effectively have a day-ahead 10 price for the operating system for that energy. 11 I might have just made it worse through my 12 explanation, but does that follow if you're following down 13 the page? What creates the situation needing that swap is 14 the fact that the day-ahead transactions were non-op 15 transactions, the real-time transactions were op. What we 16 changed in December was we allowed -- we changed all of the 17 classification to cause them all to be classified as non-op 18 so we no longer needed this transfer of real-time pricing 19 between the two books. 20 Q BY MS. NORDSTROM: Now, these charts here in 21 Exhibit 30, what time frame is this representative of? Was 22 it before or after December? 23 A It was for April 2000 through November 2000. 24 Q So this changed after December 2000? 25 A In December 2000 we started classifying all 247 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 real-time positions as non-operating, so the only thing 2 that changed is that we no longer needed this other 3 real-time transfer piece. 4 Q Okay; so if I understand you correctly, the 5 day-ahead transactions are priced at the Mid-C index? 6 A Yes. 7 Q And the non-operating transfers are priced at 8 the real-time average price? 9 A Well, all of the day-ahead transfers are 10 priced at the Mid-C index price. This real-time transfer 11 is just the other leg of that transaction to ensure that 12 the day-ahead transfer is at Mid-C average. 13 Q Okay; so what is the second transfer, what 14 price is that at? 15 A That is at the average real-time heavy load 16 or light load price at system points. 17 Q Okay; so if we go back to Staff's Exhibit 18 132, if you look at columns K and N, the prices in columns 19 K and N on page 1 are not the same prices in the 20 corresponding columns on page 2. 21 A That's right. 22 Q And that's because of this transfer 23 mechanism? 24 A Yes. 25 Q Is it correct to say that day-ahead purchases 248 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 from third parties may become day-ahead sales to Idaho 2 Power? 3 A Well, I guess that's a difficult question to 4 answer because we don't -- we haven't split up the 5 transactions to say this transaction is for sale to Idaho 6 Power and this transaction is to meet an obligation for the 7 non-operating system. All of the energy requirements of 8 non-op we source from the entire portfolio, so there could 9 have been in order to serve Idaho Power, there could have 10 been transactions from term, from day-ahead and from 11 real-time. 12 Q So in the aggregate, purchases from third 13 parties may in fact have become sales to Idaho Power at 14 some point? 15 A The physical energy from purchases from third 16 parties probably was delivered, yes, to Idaho Power. 17 Q Okay. Is it correct to say that the 18 day-ahead purchases from third parties at system points are 19 shown on Exhibit 132 on the first page in columns A through 20 H? 21 A Well, if this is in fact a copy of what we've 22 provided you guys, what we did was we said this was 23 day-ahead energy classified in the non-op book that was 24 delivered at some point through an Idaho Power intertie 25 point. 249 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 Q So all transactions touched the system, is 2 that correct, on this exhibit? 3 A On this exhibit they did, yes. 4 Q Okay; so are the day-ahead sales to Idaho 5 Power from the non-operating system shown on page 2 of this 6 exhibit in the middle section, columns I through N? 7 A I believe that's probably the case. 8 Q Now, I think the right-hand number on the 9 first page may have been cut off when it was copied by the 10 Company and that the handwritten number "11" for the month 11 of November is actually indicating November. The title 12 says "November 2000" on the top. Is it correct to say that 13 they had sales -- let me rephrase that. So for the month 14 of November is it correct to say that the heavy load hour 15 total for non-operating purchases in column 3 of page 1 16 amounted to 83,252 megawatt-hours? 17 A Day-ahead coming through system points, yes. 18 Q And is it correct that the day-ahead heavy 19 load hour sales to Idaho Power in the middle section of 20 page 2, column I, amounted to 41,377 megawatt-hours? 21 A Well, this is where I need to maybe qualify a 22 little bit because of this transfer pricing mechanism. I 23 think what has been documented as day-ahead sales and 24 day-ahead purchases on the intercompany side is overstated 25 because both sides of this transaction are included here, 250 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 so I can't tell you precisely because I don't know which of 2 these transactions was the day-ahead transaction and which 3 was the offset to real-time. I can't tell you which one 4 was which. 5 Q So for the heavy load hours in November, the 6 amounts purchased were greater than the sales to Idaho 7 Power? 8 A The amount purchased by operating system was 9 greater than the amount sold by the operating system on 10 day-ahead. 11 Q Okay. Isn't it correct to say that the light 12 load hour total purchases of 41,347 megawatt-hours as shown 13 in column F of page 1 were not greater than the light load 14 hour sales to Idaho Power of 51,012 megawatt-hours as shown 15 in page 2, column L? 16 A 41,000 is not greater than 51,000, yes. 17 Q So if I understand your response earlier, it 18 would be correct to say that the remainder of the day-ahead 19 sales to Idaho Power were probably supplied by the 20 non-operating inventory? 21 A I think that's not what I said. What I said 22 was I can't tell you how any of Idaho Power's actual energy 23 was supplied, whether it was supplied by term, day-ahead, 24 balance of the month, real-time, I can't tell you which 25 piece of the non-operating inventory as you've classified 251 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 it actually serviced the system. 2 Q Okay, but if the non-op arm was purchasing 3 less than it sold to the regulated Idaho Power, that power 4 has to come from somewhere and presumably it's inventory; 5 is that correct? 6 A Or real-time, and this may be just a point of 7 clarification, semantics, electricity can't be stored in 8 inventory, so there really isn't any inventory and that's 9 maybe a nitpick on my part. 10 Q But that would be like inventory of term 11 transactions? 12 A It would be energy priced differently. We've 13 got energy that's priced on different bases. 14 Q So it's also possible that day-ahead 15 purchases from Idaho Power could in fact at some point 16 become sales to third parties; is that possible? 17 A Yes, ultimately the energy from Idaho Power 18 will end up with a third party. 19 Q Okay. You talked earlier about how this was, 20 in essence, a swap, these transactions. Isn't the swap 21 essentially a hedge of real-time purchases at day-ahead 22 prices? 23 A Or sales, yes, it was a real-time position. 24 Q And the purpose of that hedge was that the 25 Company didn't want exposure to real-time risk? 252 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 A Yes. Well, we wanted to minimize the 2 exposure to real-time risk. 3 Q So how is this not just a short-term version 4 of the term hedging that Mr. Anderson called a price view? 5 A I guess I don't want to refer to 6 Mr. Anderson's testimony because I'm not sure what he 7 considered to be a price view, but it is essentially a 8 hedge, I would agree, that on day-ahead we wanted to make 9 sure that we had all of the energy locked up for the system 10 at a day-ahead price and not take the price risk of 11 real-time. 12 Q Okay; so the Company is willing to hedge 13 short term? 14 A The Company is willing to hedge long term, 15 also, and has done so in many cases. 16 Q And what is that short-term hedge based on? 17 A Can you clarify? 18 Q What positions or factors go into making that 19 short-term hedge? 20 A Well, if you note in the workpapers, this was 21 more of a procedural basis that happened every day because 22 the Company wanted to minimize price, the price risk of 23 real-time. There's real-time volatility. 24 Q So would you consider this a hedge based on a 25 price view? 253 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 A Well, we were certainly not taking a position 2 of whether real-time prices would go higher or lower than 3 day-ahead. We just wanted to lock in the price so as to 4 not even have the risk of a real-time price. 5 Q Okay, well, let's switch to a different 6 subject. On page 2, lines 20 through 22, you referred to 7 other utilities that were wholesale market participants. 8 Would a sample of these utilities include Avista Utilities, 9 Washington Water Power Division, PacifiCorp, Portland 10 General Electric, Sierra Pacific and Puget Power? 11 A I'm sorry, could you give me the reference 12 again? 13 Q Page 2, lines 20 through 22. 14 A Okay. I guess I would say that it is other 15 utilities. 16 Q Is it accurate to say that prior to 1997 17 Idaho Power directly bought and sold power with these 18 entities to balance system requirements? 19 A Yes. 20 Q Do all of these utilities touch Idaho Power's 21 system? 22 A You know, I can't actually tell you who 23 touches where. 24 Q How have these transactions changed since 25 1997? 254 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 A The transactions with -- 2 Q These other utilities. 3 A Well, I guess -- 4 Q Other market participants. 5 A We have other utilities and other market 6 participants that we transact with, buy and sell with. I 7 guess how it's changed is there's more market participants, 8 there's higher volumes. There's more transactions that are 9 entered into that physical delivery doesn't actually occur. 10 Q On page 12 of your testimony, lines 11 11 through 13 states that the trading group will not assume 12 forward market risk by the operating book. In other words, 13 is it accurate to say that a trader will not make a forward 14 trade for the operating book without proper approval as 15 explained in lines 13 through 22? 16 A Yes. 17 Q Are you familiar with the risk management 18 policy dated April 1999? 19 A Yes. 20 Q Is that still current? 21 A Well, at the time of this, the time frame 22 we're talking about here, it was still current. I'm not 23 sure if it's still current right now or not. 24 Q Did you participate in the making of this 25 risk management policy? 255 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 A Yeah, I had my opinions and suggestions in 2 the policy, yes. 3 Q Okay, in the risk management policy, 4 specifically objective No. 1, it states that IE will "hedge 5 Company assets in the traditional manner by reducing 6 underlying business risk." Do you have a copy of this? 7 A I don't. 8 COMMISSIONER KJELLANDER: You may approach 9 the witness. 10 MS. NORDSTROM: Thank you. 11 (Ms. Nordstrom approached the witness.) 12 Q BY MS. NORDSTROM: Okay, page 1, objective 13 1. 14 A Okay. 15 Q "IE will hedge Company assets in the 16 traditional manner by reducing the underlying business 17 risk." What does that statement mean? 18 A Well, it means that the non-op side of the 19 business, which is referred to here as IDACORP Energy, but 20 it was Idaho Power's non-op division, would perform the 21 system operations as they had done in a traditional manner 22 balancing load and resource. 23 Q Okay, and can I now refer you to Company 24 Exhibit 16 or Staff Exhibit 117? 25 A And I don't have that either. I'm sorry. 256 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 Okay, I've got our Exhibit 16. 2 MR. RIPLEY: She has IPCo's Exhibit 16. 3 MS. NORDSTROM: Okay. 4 Q BY MS. NORDSTROM: And this is a filing with 5 the Federal Energy Regulatory Commission; correct? 6 MR. RIPLEY: Actually, Exhibit 16 is the 7 agreement for electricity supply. 8 MS. NORDSTROM: I'm sorry. 9 Q BY MS. NORDSTROM: Okay, in Statement of 10 Services, item 2.1 -- 11 A What page is that on? 12 Q That's the first page. 13 A I'm lost, I'm sorry. 14 Q Attachment 1, I'm sorry. 15 COMMISSIONER SMITH: 7 of 13. 16 THE WITNESS: Okay, I'm with you now. 17 Q BY MS. NORDSTROM: Isn't it correct that 18 forward transactions for the purpose of hedging continued 19 to be anticipated in 2000 in this Statement of Services 20 2.1? 21 A Appropriate forward hedging has always been 22 considered to be part of what Idaho Power would look at. 23 Q Is it correct to characterize this statement 24 of services as saying that IES will provide Idaho Power 25 with the power marketing and system resource management 257 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 functions which would include 2.1.3, hedging management and 2 that also says, "Hedges are executed with the use of 3 financial instruments such as forwards, swaps, futures or 4 options contracts," do you think that's a fair 5 characterization of what's in this service agreement? 6 A Well, that is what you've read. I'm sure 7 somewhere else in this agreement it does mention that the 8 forward hedging has to be approved by the Idaho Power 9 management. 10 Q Directing your attention to item No. 2.1.7 11 which is on page 9 of 13 in Company Exhibit No. 16, it 12 states that risk management activities reduce the 13 occurrence of losses that would cause Idaho Power to incur 14 higher costs for supplying native load; is that correct? I 15 believe that's the first sentence. 16 A That is what it says. 17 Q And the last sentence identifies the risks to 18 be managed. What does that include? 19 A Well, this says, "Risks to be managed include 20 power prices, volatility, interest rates, counterparty 21 credit risk and foreign currency fluctuations." 22 MS. NORDSTROM: Thank you. I have no further 23 questions at this time. 24 COMMISSIONER KJELLANDER: Thank you. 25 Mr. Richardson? 258 CSB REPORTING HOYD (X) Wilder, Idaho 83676 Idaho Power Company 1 MR. RICHARDSON: Thank you, Mr. Chairman, no 2 questions. 3 COMMISSIONER KJELLANDER: And questions from 4 the Commission? 5 Commissioner Smith. 6 7 EXAMINATION 8 9 BY COMMISSIONER SMITH: 10 Q Yeah, is the day-ahead price always better 11 than real-time? 12 A No, no. 13 COMMISSIONER SMITH: Thank you. 14 COMMISSIONER KJELLANDER: Redirect. 15 MR. RIPLEY: Can I confer with my witness for 16 a moment? I don't know if I have any. Can I have five 17 minutes? 18 COMMISSIONER KJELLANDER: Certainly. We'll 19 go off the record. 20 (Pause in proceedings.) 21 COMMISSIONER KJELLANDER: Mr. Ripley, you had 22 redirect? 23 MR. RIPLEY: Yes, I do. 24 25 259 CSB REPORTING HOYD (Com) Wilder, Idaho 83676 Idaho Power Company 1 REDIRECT EXAMINATION 2 3 BY MR. RIPLEY: 4 Q The only question I have is referring to 5 what's been marked as Exhibit 30, there are seven pages, 6 are there seven examples here even though you only went 7 through one? 8 A Yes. 9 Q So if I were to read this exhibit just very, 10 very briefly, take me through page 1 just so that I would 11 understand what you're -- 12 A What the differences are? What I've done 13 here is showed how the transactions would process depending 14 on the position of the non-op side of the house and the 15 position of the operating side of the house, so page 1 16 shows an example if at the end of the day-ahead trading 17 non-op position was long and the operating position was 18 long. Page 2 shows an example where the non-op position 19 exactly offsets the operating position and so on through 20 the other examples. 21 MR. RIPLEY: All right. That's all the 22 questions that we have. Thank you. 23 COMMISSIONER KJELLANDER: Thank you very much 24 and, Ms. Hoyd, you are excused for now. I believe, though, 25 that you are on the rebuttal list. Okay, thank you for 260 CSB REPORTING HOYD (Di) Wilder, Idaho 83676 Idaho Power Company 1 your testimony. 2 (The witness left the stand.) 3 COMMISSIONER KJELLANDER: And I guess we're 4 ready for your next witness. 5 MR. RIPLEY: Call Mr. Gale. 6 7 JOHN R. GALE, 8 produced as a witness at the instance of the Idaho Power 9 Company, having been first duly sworn, was examined and 10 testified as follows: 11 12 DIRECT EXAMINATION 13 14 BY MR. RIPLEY: 15 Q Would you state your full name for the 16 record, please? 17 A John R. Gale. 18 Q And your business address? 19 A 1221 Idaho Street, Boise. 20 Q And did you have cause to be prepared for 21 this proceeding certain prefiled direct testimony 22 consisting of eight pages? 23 A Yes, I did. 24 Q And in that testimony, did you also identify 25 what's been marked as Exhibit No. 16? 261 CSB REPORTING GALE (Di) Wilder, Idaho 83676 Idaho Power Company 1 A That's correct. 2 Q And if I asked you the questions set forth in 3 your testimony, would your answers be the same today? 4 A Yes, they would. 5 MR. RIPLEY: We would request that Mr. Gale's 6 direct testimony be spread upon the record as if read and 7 would note that Exhibit No. 16 has been marked for 8 identification in that prefiled testimony and would tender 9 Mr. Gale for cross-examination. 10 COMMISSIONER KJELLANDER: Then without 11 objection, the direct testimony and the exhibit will be 12 spread across the record. 13 (The following prefiled testimony of 14 Mr. John Gale is spread upon the record.) 15 16 17 18 19 20 21 22 23 24 25 262 CSB REPORTING GALE (Di) Wilder, Idaho 83676 Idaho Power Company 1 Q. Please state your name and business address. 2 A. My name is John R. Gale and my business 3 address is 1221 West Idaho Street, Boise, Idaho. 4 Q. By whom are you employed and in what 5 capacity? 6 A. I am employed by Idaho Power Company; as the 7 Vice President of Regulatory Affairs. 8 Q. Please describe your work experience. 9 A. In October 1983, I accepted a position as 10 Rate Analyst with Idaho Power Company. In March 1990, I 11 was assigned to the Company's Meridian District Office for 12 one year where I held the position of Meridian Manager. In 13 March 1991, I was promoted to Manager of Rates. In July 14 1997, I was named General Manager of Pricing and Regulatory 15 Services. In March of 2001, I was promoted to Vice 16 President of Regulatory Affairs. As Vice President of 17 Regulatory Affairs, I am responsible for the overall 18 coordination and direction of the department, including 19 development of jurisdictional revenue requirements and 20 class cost-of-service studies, preparation of rate design 21 analyses, and administration of tariffs and customer 22 contracts. In my current position, I am actively involved 23 with restructuring activities throughout our service 24 territory. 25 Q. Are you familiar with the Electricity Supply 263 GALE, DI 1 Idaho Power Company 1 Management Agreement ("Agreement") between IDACORP Energy 2 Solutions LP ("IES") and Idaho Power Company? 3 A. Yes, I was actively involved in the 4 development of the Agreement that I have enclosed as 5 Exhibit 16. 6 Q. What was the purpose of the Agreement? 7 A. The Agreement outlines the provisions for 8 interactions between the utility, Idaho Power Company, and 9 the affiliate, IES. These transactions allow the affiliate 10 to continue to provide power supply management services to 11 the utility under specific terms and conditions. 12 Q. Why is the Agreement necessary? 13 A. The Agreement is necessary in order to move 14 the trading function out from the utility and into a 15 separate affiliate. The Agreement is part of a long-term 16 plan for separation of the trading activity from the 17 utility. The primary reason that separation is desirable 18 is that it aligns risk and reward appropriately between the 19 two entities. The utility is insulated from the more 20 speculative transactions inherent in the trading business. 21 The second benefit of the separation is that it allows both 22 the utility and the affiliate to achieve the benefits of 23 the economies of one trading floor. 24 Q. Please summarize the process undertaken in 25 Case No. IPC-E-00-13. 264 GALE, DI 2 Idaho Power Company 1 A. From the start, Idaho Power pursued a 2 settlement process in this case because the Company desired 3 that the parties be comfortable with the way Idaho Power 4 and IES conducted business transactions. The Company 5 discussed its view of the affiliate arrangement with 6 customers ahead of any formal action, filed a straw-man 7 application, conducted informational workshops, and pursued 8 a settlement stipulation. Ultimately, all parties involved 9 in the case, but one, signed the Stipulation previously 10 identified as Exhibit 12. 11 Q. What were the issues involved in seeking 12 settlement in this case? 13 A. The primary issues were: (1) what were to be 14 the customer benefits of the transaction, (2) what would be 15 the annual charges for services provided by IES, (3) how 16 would transmission reservations be undertaken, and (4) 17 general contract provisions. 18 Q. Please describe the customer benefits 19 envisioned by the Stipulation in Case No. IPC-E-00-13. 20 A. The Stipulation provides both direct and 21 indirect benefits to the customer. First, the Stipulation 22 outlines Idaho Power's commitment to facilitate commission 23 audits. Such a provision assures commission staff adequate 24 access to books and records for audit purposes and assures 25 procedures, transactions and prices are reasonable. Second, 265 GALE, DI 3 Idaho Power Company 1 the Stipulation addresses economic dispatch of system 2 resources by providing a mechanism to assure that system 3 assets are secured for the benefit of native load customers 4 and that surplus power from system resources is sold at 5 prices that are reasonable and consistent with prudent 6 utility practice. Third, the Idaho retail customers 7 receive a direct benefit of $2,000,000 annually that will 8 flow back coincidental with Idaho Power's PCA until the 9 Company's next general rate proceeding. 10 Q. Please describe the annual charges for 11 services provided by IDACORP Energy Solutions. 12 A. The contract charges initially established in 13 the Agreement between Idaho Power and IES provide that IES 14 will be paid $300,696.30 per month for services rendered to 15 Idaho Power. IES will pay Idaho Power $87,293.53 per month 16 for non-power goods and services provided by Idaho Power. 17 The dollar amount will be reviewed and established each 18 year. The payment to IES of $3,608,355.60 annually 19 ($300,696.30*12) is less than the $4,870,263 cost for these 20 services included in the last rate case. The contract cost 21 is also significantly less than the total amount incurred by 22 Idaho Power in 1999 for all transactions. The Stipulation 23 also provides that the annual charge paid to IES from Idaho 24 Power will not exceed $5,000,000 in the next rate case. 25 Q. Please describe the transmission provisions 266 GALE, DI 4 Idaho Power Company 1 in the Stipulation. 2 A. The Transmission Reservations provision in 3 the Stipulation requires Idaho Power to take the necessary 4 steps to ensure that the Agreement between Idaho Power and 5 IES will not result in any reduction in Idaho Power's 6 allocation of capacity in its transmission system for Idaho 7 Power's retail customers. 8 Q. Please describe the other general provisions 9 to the Agreement. 10 A. Under the General Provisions of the 11 Stipulation the Parties agree that the Stipulation and the 12 Agreement between Idaho Power and IES is in the public 13 interest. The Parties also agree to cooperate and support 14 approval of the Application and Agreement in any comments 15 they submit. 16 Q. What is the status of the Agreement before 17 the regulators that are involved in approving the Agreement? 18 A. The Stipulation was approved by the Idaho 19 Public Utilities Commission ("IPUC") at the conclusion of 20 Case No. IPC-E-00-13 on December 19, 2000. The case is 21 before the Oregon Public Utility Commission ("OPUC") at 22 present and an order is expected to be issued by the end of 23 June. The issue before the Federal Energy Regulatory 24 Commission ("FERC") is different from the state commissions, 25 in that the issue before the FERC is the granting of a power 267 GALE, DI 5 Idaho Power Company 1 marketer's license to IES. The Company received authority 2 for that license on April 27, 2001. Idaho Power has made 3 compliance filings with the FERC on May 14, 2001. At this 4 time, IES may conduct business under a power marketer's 5 license and under the provisions established by the FERC. 6 Q. As a result of the Agreement being approved 7 by the Idaho Public Utilities Commission in Case No. 8 IPC-E-00-13, were any of the provisions of the Agreement 9 utilized by the Company for transfer pricing? 10 A. Yes, the Company adopted the transfer price 11 for real-time hourly transactions once the IPUC approved 12 the Electricity Supply Management Agreement. This change 13 was implemented not because the Agreement had become 14 effective, but because once the Agreement and the transfer 15 pricing were approved by the IPUC, the Company viewed the 16 new real-time transfer price as the appropriate price. 17 Q. When did the Company make the change to the 18 real-time hourly pricing? 19 A. The Company made the change in December 2000. 20 Q. Please describe the transfer price used prior 21 to December 2000. 22 A. Prior to December 2000, there were relatively 23 few real-time transactions occurring between the "operating" 24 and "non-operating" business groups. All real-time 25 transactions (but for a few specifically tagged as non- 268 GALE, DI 6 Idaho Power Company 1 operating) were classified as operating. 2 Q. Please describe the transfer price used after 3 December 2000. 4 A. The weighted average of real-time prices in 5 the relevant market at which IES bought and sold power to 6 non-affiliates. The average of these transactions is 7 indicative of the market price for that time period and its 8 use provides appropriate protection against affiliate 9 abuse. It is a price established by third party criteria, 10 which I believe is in the public interest. 11 Q. How are Idaho retail customers impacted by 12 hourly transfer pricing? 13 A. The transfer price multiplied by the quantity 14 becomes either the power purchase or surplus sale value 15 used for Power Cost Adjustment ("PCA") computations. 16 Q. Turning to the conclusion of this case, once 17 the Idaho Public Utilities Commission has made its 18 determination as to the $59,211,603 in deferred expenses, 19 what are the ratemaking options available? 20 A. I recommend the Idaho Public Utilities 21 Commission take one of two courses of action. The first 22 would be to authorize a rate to collect the additional 23 amount over one year with implementation occurring shortly 24 after the issuance of the appropriate IPUC order. The 25 equivalent rate for the full $59 million would be .5481 269 GALE, DI 7 Idaho Power Company 1 cents per kilowatt-hour before any additional interest for 2 the period from March 1, 2001 to the time of 3 implementation. I have been advised that due to cash flow 4 and capitalization concerns, the Company's preference is to 5 implement a one-year rate change as soon as possible. The 6 second method would be to include the amount in the 7 appropriate month of the PCA deferral account and to 8 continue to defer the amount until the next rate action. 9 That rate action could be next year's Power Cost Adjustment 10 filing or it could be a securitization filing submitted 11 prior to the next PCA rate change. 12 Q. Does this conclude your testimony? 13 A. Yes, it does. 14 15 16 17 18 19 20 21 22 23 24 25 270 GALE, DI 8 Idaho Power Company 1 (The following proceedings were had in 2 open hearing.) 3 COMMISSIONER KJELLANDER: And that now takes 4 us to cross from the Deputy Attorney General representing 5 the PUC Staff. 6 7 CROSS-EXAMINATION 8 9 BY MS. NORDSTROM: 10 Q Good afternoon. Directing your attention to 11 page 3 of your testimony, lines 23 through 25, you state 12 that a provision in the stipulation assures Commission 13 Staff adequate access to books and records for audit 14 purposes and assures procedures, transactions and prices 15 are reasonable. Under the agreement if during an audit the 16 Staff finds that procedures, transactions and prices are 17 not reasonable during a particular period, can the Staff 18 recommend adjustments for the period? 19 A At the time of a PCA period is what you're 20 referring to? 21 Q Yes. 22 A Well, I think the Staff is not bashful in 23 doing so. 24 Q Directing your attention to page 6, you state 25 that the Company implemented some of the agreement 271 CSB REPORTING GALE (X) Wilder, Idaho 83676 Idaho Power Company 1 provisions before the agreement actually took effect. Is 2 that a common Company practice? 3 A I'm not sure if it's a common practice or 4 not. There was a reason we did. 5 Q And what was that reason? 6 A Well, the reason we did is that the 7 transactions to which we would apply the real-time transfer 8 pricing were ongoing. They were going on at the time that 9 we received the Commission Order, so in our collective 10 view, that was an endorsement of that transfer price and to 11 not use it to me anyway seemed a more risky track to take 12 than to implement it. 13 Q Did the Company implement all the terms of 14 the agreement prior to receiving the final approvals? 15 A No. 16 Q So is it fair to say that the Company chose 17 which provisions it would implement and which ones it 18 wouldn't? 19 A The Company implemented the transfer prices 20 because in good faith we thought that was the direction the 21 Commission had approved, had authorized. 22 Q In your testimony on page 6, you indicate 23 that the pricing methodology was changed in December 2000 24 after the service agreement was approved by the 25 Commission. Wasn't the pricing methodology actually 272 CSB REPORTING GALE (X) Wilder, Idaho 83676 Idaho Power Company 1 applied for the entire PCA year prior to the agreement 2 approval as was indicated by Company witness Hoyd's direct 3 testimony? 4 A We're talking about real-time here and not 5 the day-ahead? 6 Q Yes. 7 A Okay. My understanding is that we -- the 8 only thing we changed in December 2000 was the real-time 9 and at such time we moved to the average of the actual 10 relevant transactions for the hour. That's the only thing, 11 I think, we changed in the year 2000. I think prior to 12 that, I think Ms. Hoyd addressed that in her testimony. 13 Q Well, Ms. Hoyd's testimony said that all the 14 transactions from April 2000 were priced according to the 15 methodology that was approved in December 2000; is that 16 your understanding? 17 A Unless there's a confusion about Mid-C. For 18 day-ahead we used Mid-C consistently throughout the whole 19 period, but for real-time, I understand we made a change in 20 December and I see a head nod. 21 Q Isn't it true that the service agreement was 22 recently modified as a condition of FERC approval? 23 A That's correct. 24 Q And are those changes to be approved by this 25 Commission? 273 CSB REPORTING GALE (X) Wilder, Idaho 83676 Idaho Power Company 1 A As we've tried to navigate three commissions, 2 it's been a little bit of tail chasing. Because FERC is 3 the conveyor of the license, it's our view that we have to 4 price at FERC prices for the time being and then I forgot 5 where I was going. Ms. Nordstrom, could you help me with 6 the original question? 7 Q Are the changes made by FERC as part of their 8 conditional approval going to be submitted for approval by 9 this Commission? 10 A The FERC adjusted the real-time pricing 11 differently than the weighted average. It's the Company's 12 position that the weighted average is still the best way to 13 do real-time. We are going back the first part of 14 September to talk with FERC staff to see if we can yet get 15 their approval to use our methodology, the weighted average 16 methodology, for real-time. Once that's accomplished, we 17 hope to take the final result and have that applied to this 18 Commission; otherwise, you just continually chase trying to 19 find what you really have for prices. 20 Q Okay. Now, I know you said earlier that the 21 Company didn't implement other provisions of the agreement 22 early and I guess I just want -- is it your testimony it 23 was just the pricing methodology that changed, that was the 24 only thing that was implemented from the agreement? 25 A Well, there are things in the agreement, much 274 CSB REPORTING GALE (X) Wilder, Idaho 83676 Idaho Power Company 1 like some of the items you were asking Ms. Hoyd about, 2 there are things in the agreement that were already 3 occurring between op and non-op on an ongoing basis. They 4 just became formalized into the agreement, such as some of 5 the marketing expertise and risk management expertise. 6 Q Well, this service agreement contemplated an 7 oversight risk manager. Was that in place in December of 8 2000? 9 A No, in December of 2000 it was the Risk 10 Management Committee that was overseeing the transactions 11 for the system. 12 Q And what was the purpose of the oversight 13 risk manager? 14 A Actually, I believe there was intended to be 15 two, one on behalf of the affiliate and one on behalf of 16 the utility so we could have a primary responsible officer 17 for each in conducting the transactions. 18 Q So there wasn't an oversight risk manager 19 specifically looking out for ratepayers at the point that 20 this pricing mechanism was implemented; correct? 21 A At the time the ratemaking mechanism was 22 implemented, December of 2000, the RMC would be fulfilling 23 that role looking out for the system. 24 Q But it hadn't been split out yet into 25 specific groups; correct? 275 CSB REPORTING GALE (X) Wilder, Idaho 83676 Idaho Power Company 1 A No, it had not been split out. 2 MS. NORDSTROM: No further questions at this 3 time. 4 COMMISSIONER KJELLANDER: Mr. Richardson? 5 MR. RICHARDSON: No questions, Mr. Chairman. 6 COMMISSIONER KJELLANDER: Questions from the 7 Commission? 8 Commissioner Hansen. 9 10 EXAMINATION 11 12 BY COMMISSIONER HANSEN: 13 Q A couple of questions just to kind of verify 14 what I believe you said to the questioning of Staff. You 15 are saying, then, that since neither FERC nor the Oregon 16 Public Utilities Commission had approved the agreement 17 during the period in question that it was not legally 18 approved and really had not become effective and that you 19 really didn't follow the entire agreement as outlined to be 20 approved, you took mainly the pricing and that was the 21 major area you took; is that correct? 22 A I think the real-time, not Mid-C, I want to 23 be clear about that, Mid-C we were already doing exactly 24 the same transfer pricing, we did not change the Mid-C 25 pricing, but the real-time we changed as a result of that 276 CSB REPORTING GALE (Com) Wilder, Idaho 83676 Idaho Power Company 1 Order because we thought that that was, with a recent 2 approval that was, the Commission's desire to use that 3 price. Now, the rest of the agreement was not in effect, 4 so we didn't implement the other provisions until it was 5 effected. 6 Q But you thought that was in effect and 7 approved; is that correct? 8 A We thought it was legitimate might be better 9 and the reason I say that is we had an Order that covered 10 an agreement that covered prices. One set of prices we 11 already were doing and the other set of prices with the 12 Order, we were conducting those transactions and to me to 13 not change the pricing method with that Order seemed a 14 precarious position to take. 15 Q Let me just kind of make a comparison here 16 and it may be a lousy example, but let's just say for an 17 example I wanted to drive a vehicle and they told me, they 18 said, okay, you've got vehicle, you've got to get a 19 driver's license, you've got to get it registered and 20 licensed, you've got to get insurance on it and you've got 21 to put gas in it and once you do that, then, hey, you can 22 drive anywhere you want and do what you want, and so I go 23 out and I get -- I think, well, yeah, that's what they want 24 me to do, so I go register it and I get the plates on it 25 and I go put gas in it and then I start driving it around. 277 CSB REPORTING GALE (Com) Wilder, Idaho 83676 Idaho Power Company 1 Legally, do I have any authority to really drive that 2 automobile? I don't until it's gone through all four 3 steps. Isn't that kind of what you've done here? You've 4 said, okay, I put gas in the car, I got the driver's 5 license and now we're going to implement that, but it 6 really takes a lot more than that to do it, to have the 7 complete agreement which took the other approvals. Is that 8 a comparison that's similar? 9 A I think -- I can't think of the piece of the 10 analogy that I would save for this transfer pricing, 11 because in your analogy you talk about driving a car, there 12 would be a piece of your analogy that would have to be 13 ongoing all the time anyway and that's what we're saying. 14 Real-time transactions were going on at that time, ongoing 15 at that time. We had the Order that spoke to real-time 16 transfer pricing and we thought we had the basis to make a 17 change. In hindsight, maybe that was premature, but we 18 thought in total good faith with that Order we should be 19 pricing it different for real-time. 20 Q Let me ask you one other question kind of 21 concerning this. During the winter months the price of 22 electricity was very expensive and one of the problems 23 identified early in California was the utility companies 24 could only purchase power on day-ahead or hour-ahead 25 markets. Would you agree that that was one of the 278 CSB REPORTING GALE (Com) Wilder, Idaho 83676 Idaho Power Company 1 problems? 2 A I would agree that one of the problems in 3 California is they forced everything to the short-term 4 markets, yes. 5 Q So I guess my question is, isn't that exactly 6 what IES did in managing Idaho Power's needs, buying only 7 on the day-ahead and hour-ahead spot market? I mean, 8 weren't you doing exactly what they were doing in 9 California during this period of time? 10 A Well, I'll take another run because I know 11 that we may be frustrating you with our answers, but we're 12 not intending to do that. The Company throughout this PCA 13 year did take longer-term positions. There are hedges in 14 the year we're talking about. Those hedges were presented 15 to Staff in an audit response, so there are times when we 16 did take action. The circumstances in November is that we 17 were looking at a month that was short in a quarter that 18 was long. 19 We had the ability through our hydro system 20 to move water into that short month and the prices were 21 already up, so the decision at that time was to cover a 22 shortfall we might be able to cover through operations 23 versus locking in to a higher price and you know throughout 24 the rest of the year there were many things that we did to 25 try to take positions for the benefit of the customer, but 279 CSB REPORTING GALE (Com) Wilder, Idaho 83676 Idaho Power Company 1 we did not choose to do that in November. 2 Q So could you give me an explanation of 3 exactly some of the mitigated risks that you took in 4 November and how they benefited the regulated customer? 5 A November I cannot tell you that we took 6 action because we did not take action, again, because at 7 that time we didn't know if we really were going to be 8 short or long in January. 9 Q What about December? 10 A Well, one thing I know we did in December, a 11 variety of things in December, specifically one transaction 12 we did is we did a transaction with Simplot for a couple of 13 weeks in December we brought to your folks, so we were able 14 to buy load reduction at a cheaper price. We came and 15 asked for orders to keep California off our back in 16 December. We put out press releases in December. Not all 17 of those are specific risk management tools, but they are 18 all things the Company did to try to manage on behalf of 19 its customers during that time period. 20 Q Just a ball park number and maybe you don't 21 have a number, but given the PCA filing of 220 million, 22 what value or benefit would you say the risk mitigation you 23 talked about made? 24 A Commissioner, I believe that we responded to 25 that in an audit request and if it's possible to bring that 280 CSB REPORTING GALE (Com) Wilder, Idaho 83676 Idaho Power Company 1 on a rebuttal piece, we'd like to introduce that at the 2 time we come back up because I believe we've already put 3 that together in response to an audit. 4 COMMISSIONER HANSEN: That would be fine. I 5 believe that's all the questions I've got. Thank you. 6 7 EXAMINATION 8 9 BY COMMISSIONER KJELLANDER: 10 Q Mr. Gale, I have one question. Prior to the 11 Company making the Mid-C change in December which was a 12 limited change based on what you said earlier, was there 13 any discussion within the Company about seeking Commission 14 approval about making that specific Mid-C change knowing 15 that the entire agreement had not yet been approved, hadn't 16 received all the necessary approvals from FERC and Oregon? 17 A Thank you for that question. The reason I'm 18 thanking you is you just asked me about a Mid-C change and 19 if I can make one point to you is we did not make a Mid-C 20 change in December. The Mid-C is related to the day-ahead 21 pricing and the day-aheads we've been doing since January 22 of 1999, using Mid-C the same way since January of 1999 and 23 if I can leave you with one impression, I'd like to leave 24 you with that one. Now, specifically, we did make a change 25 to the real-time, the other part of it. 281 CSB REPORTING GALE (Com) Wilder, Idaho 83676 Idaho Power Company 1 Q That's the part I was referring to. 2 A Okay, and getting to that is no, we didn't 3 have a discussion because we thought clearly it was the 4 right thing to do to make the price change at that time. I 5 can remember no discussion of needing to clarify should we 6 make a pricing change at that time. We got the Order, it 7 seemed, it just seemed, to us clear that we should make the 8 pricing change on real-time. 9 Q Even though the language of that Order was 10 still dependent on other approvals? 11 A Well, it appears at this point in time 12 there's a different view. It was crystal clear to me that 13 we should be making the real-time change. 14 COMMISSIONER KJELLANDER: Thank you very 15 much. 16 We're ready now for redirect. 17 18 REDIRECT EXAMINATION 19 20 BY MR. RIPLEY: 21 Q Mr. Gale, if I could attempt to put in 22 context what we're talking about, there's roughly 23 $51.2 million of transfer pricing at issue in this deferral 24 case; is that correct? 25 A Of repricing? 282 CSB REPORTING GALE (Di) Wilder, Idaho 83676 Idaho Power Company 1 Q Yes. 2 A Yes. 3 Q How much is this real-time pricing issue? 4 Have you attempted to quantify that? 5 A Well, the real-time pricing piece, the piece 6 that we changed in December 2000, the real-time pricing 7 piece is by far the smallest piece of it and on a 8 jurisdictional basis is around 3.6 million and all I'm 9 doing there is taking Ms. Carlock's number and taking an 10 Idaho jurisdictional allocator to it. 11 Q Okay. Now, if I could take you back to the 12 time when I assume the Commission had issued an Order 13 approving the IDACORP agreement; would that be correct? 14 A That's correct. 15 Q Leading up to the approval of that IDACORP 16 agreement, were there workshops with the various parties? 17 A Yes, there were. 18 Q Coming out of those workshops, was there 19 consent amongst all of the parties as to how real-time 20 should be priced? 21 A All parties but one signed the settlement 22 agreement. 23 Q Did the Staff concur in the new method? 24 A Staff signed the settlement stipulation. 25 Q And then you obtained an Order from the Idaho 283 CSB REPORTING GALE (Di) Wilder, Idaho 83676 Idaho Power Company 1 Commission; is that correct? 2 A That's correct. 3 Q Did you assume since you had had workshops 4 and that you had an Order as to how real-time pricing was 5 to occur that it was prudent to use that method of pricing? 6 A Yes. 7 Q Did the Company have an ongoing obligation 8 every day to engage in real-time purchasing? 9 A Yes. 10 Q As a result of that obligation for real-time 11 purchasing, did the Company have a view as to whether or 12 not the method of real-time pricing, the change, if you 13 will, was beneficial or detrimental to the utility side of 14 the house? 15 A We think it's beneficial to the utility side 16 of the house and still do, hence, our trip to FERC. 17 Q And why is that beneficial? Can you briefly 18 explain to me what the benefit is? 19 A Well, the real-time methodology uses the 20 weighted average of actual transactions in the relevant 21 market and by that, I mean those that touch the Idaho Power 22 system for that hour, and since there is no market index, 23 it is in our view the best possible second alternative. 24 Q Now, if I could give you an analogy of 25 Commissioner Hansen's vehicle, if I could change his 284 CSB REPORTING GALE (Di) Wilder, Idaho 83676 Idaho Power Company 1 hypothetical only to the extent that this is a bus that 2 we're talking about, it has gas, it has license plates, 3 it's got the whole nine yards and I'm required every day to 4 drive the bus. Now, what do I do if I have this 5 requirement and yet I need to transfer the license or I 6 need to transfer the title to somebody, is that your 7 dilemma that you're confronted with, that you have to drive 8 the bus and there may be a technical requirement? 9 A Well, I don't know if that analogy helps, but 10 the dilemma is that the transactions are ongoing, so now 11 you can choose to use the newly approved agreement that has 12 that transfer price in it or not, and I have said now that 13 we viewed not using the new pricing as a more precarious 14 position than using the new pricing. 15 Q All right, one final question on your 16 direct. There is apparently confusion that the Company is 17 contending that it is relying upon the 00-13 Order to 18 determine the use of Mid-C for day-ahead transactions. Is 19 that the position of the Company? 20 A No. 21 Q What is the position of the Company in 22 reference to day-ahead transactions? 23 A The day-ahead transactions are priced at 24 Mid-C and have been since January of 1999, virtually two 25 years ahead of that Order that we're talking about. 285 CSB REPORTING GALE (Di) Wilder, Idaho 83676 Idaho Power Company 1 Q Were there other orders that authorized in 2 your opinion the use of Mid-C for day-ahead? 3 A Well, I think as laid out in Mr. Said's 4 testimony, when we've used Mid-C for two years, we've gone 5 through two sets of audits, have two sets of PCA orders 6 that have transactions involving Mid-C pricing. 7 MR. RIPLEY: That's all the questions I 8 have. Thank you. 9 COMMISSIONER KJELLANDER: Thank you. 10 (The witness left the stand.) 11 COMMISSIONER KJELLANDER: I guess does that 12 conclude your direct? 13 MR. RIPLEY: Yes, sir. 14 COMMISSIONER KJELLANDER: At this point we're 15 looking at an hour and we might as well use it and get 16 started, then, with the PUC Staff's direct testimony, so I 17 believe now we'll move to that. 18 MR. RIPLEY: What's the pleasure of the 19 Commission on the admission of exhibits? 20 COMMISSIONER KJELLANDER: I think we've kind 21 of allowed the admission as -- specifically, what's your 22 question? 23 MR. RIPLEY: I would offer Exhibits 1 through 24 16 if this is the appropriate time. 25 COMMISSIONER KJELLANDER: This would be fine, 286 CSB REPORTING GALE (Di) Wilder, Idaho 83676 Idaho Power Company 1 that they be spread across the record? 2 MR. RIPLEY: No, they be admitted. 3 COMMISSIONER KJELLANDER: Admitted? 1 4 through 16, then, without objection, will be admitted. 5 MR. RIPLEY: Thank you. 6 COMMISSIONER KJELLANDER: Thank you. 7 MR. RIPLEY: And Exhibit 30, I'm sorry. 8 COMMISSIONER KJELLANDER: With the inclusion 9 of Exhibit 30, without objection, will also be admitted. 10 (Idaho Power Company Exhibit Nos. 1 - 16 11 were admitted into evidence.) 12 MS. NORDSTROM: I'm sorry, did you include 13 Staff's exhibit as well? 14 COMMISSIONER KJELLANDER: He did not. 15 MS. NORDSTROM: Okay, Staff's Exhibit 16 No. 132. 17 COMMISSIONER KJELLANDER: So then you're 18 requesting that that be admitted? 19 MS. NORDSTROM: Yes. 20 COMMISSIONER KJELLANDER: So without 21 objection, Staff Exhibit 132 will be admitted as well. 22 (Staff Exhibit No. 132 was admitted into 23 evidence.) 24 COMMISSIONER KJELLANDER: Does that bring us 25 up to speed on all the exhibits? Subject to check, okay. 287 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 MS. NORDSTROM: I know that the Staff had 2 notified the Commission that it intended to call Terri 3 Carlock first; however, given the lateness in the day and 4 the amount of time that I estimate it will take to put her 5 testimony on, I'd like to call Rick Sterling instead if 6 there's no objection. 7 COMMISSIONER KJELLANDER: Without objection, 8 Mr. Sterling. 9 MR. RIPLEY: I don't have an objection, but 10 could I have about ten minutes? I had anticipated 11 Ms. Carlock. 12 COMMISSIONER KJELLANDER: I think that's 13 certainly appropriate. We'll give you ten minutes. Why 14 don't we take a ten-minute break. I think everybody would 15 appreciate that. 16 MR. RIPLEY: Thank you. 17 COMMISSIONER KJELLANDER: We'll go off the 18 record. 19 (Recess.) 20 COMMISSIONER KJELLANDER: We're back on the 21 record. 22 23 24 25 288 CSB REPORTING COLLOQUY Wilder, Idaho 83676 1 RICK STERLING, 2 produced as a witness at the instance of the Staff, having 3 been first duly sworn, was examined and testified as 4 follows: 5 6 DIRECT EXAMINATION 7 8 BY MS. NORDSTROM: 9 Q Good afternoon. 10 A Good afternoon. 11 Q Please state your name and spell your last 12 name for the record. 13 A My name is Rick Sterling, S-t-e-r-l-i-n-g. 14 Q And by whom are you employed and in what 15 capacity? 16 A I'm employed by the Idaho Public Utilities 17 Commission as a Staff engineer. 18 Q Are you the same Rick Sterling that filed 19 direct testimony on July 20th and prepared Exhibits 20 Nos. 101 through 106? 21 A Yes, I am. 22 Q Do you have any corrections or changes to 23 your testimony or exhibits? 24 A No, I do not. 25 Q If I were to ask you the questions set out in 289 CSB REPORTING STERLING (Di) Wilder, Idaho 83676 Staff 1 your prefiled testimony, would your answers be the same 2 today? 3 A Yes. 4 MS. NORDSTROM: I would move that the 5 prefiled testimony of Rick Sterling be spread upon the 6 record as if read and Exhibits 101 through 106 be marked 7 for identification. 8 MR. RIPLEY: We have a preliminary objection 9 to Mr. Sterling's testimony. 10 COMMISSIONER KJELLANDER: If you'd like to 11 elaborate and turn on your microphone. 12 MR. RIPLEY: Yes, we have a preliminary 13 objection that I would like to state as follows: Upon 14 receipt of Mr. Sterling's testimony, Idaho Power Company 15 sent some requests for information, i.e., interrogatories 16 to Staff and the questions were as follows: "Is the direct 17 testimony of Rick Sterling intended to be filed exclusively 18 in the consolidated dockets Case No. IPC-01-07 and 19 IPC-E-01-11?" 20 And the answer came back, "No. The direct 21 testimony of Rick Sterling was purposely filed under all 22 three case numbers for comprehensive consideration of the 23 historical, interim and prospective issues identified in 24 Order Nos. 28722 and 28738." 25 Those dockets are, of course, the IPC-E-01-16 290 CSB REPORTING STERLING (Di) Wilder, Idaho 83676 Staff 1 case. We then went on further and asked an additional 2 question, and that is, "If the answer to Request No. 5 is 3 no or if the response is that the testimony is intended to 4 be filed in all three dockets, i.e., the consolidated 5 Dockets IPC-E-01-07, IPC-E-01-11 and Docket IPC-E-01-16, 6 then please specify by line numbers and page numbers that 7 portion of the direct testimony of Rick Sterling that is 8 intended to address the issues the Commission has 9 identified for investigation in the consolidated dockets 10 IPC-E-01-07 and IPC-E-01-11." 11 In response to that, the Commission Staff 12 filed the answer, "Although Rick Sterling's direct 13 testimony addresses issues the Commission has identified 14 for investigation in Case No. IPC-E-01-16, the following 15 sections also address issues the Commission has identified 16 for investigation in the IPC-E-01-07 and IPC-E-01-11 17 cases," and then was listed on Mr. Sterling's testimony the 18 following: page 1, lines 1 through page 8, line 17; and 19 page 16, line 11 through page 21, line 11; page 16, 20 line 11 through page 21, line 11. 21 Accordingly, we would move to strike the 22 other portions of Mr. Sterling's testimony as they are not 23 relevant to IPC-E-01-7 or 11 and in fact, we believe 24 prejudice the record by discussing matters which occurred 25 after IPC-E-01-7/11 and create a very convoluted and 291 CSB REPORTING STERLING (Di) Wilder, Idaho 83676 Staff 1 complicated factual situation which is extremely difficult 2 for the Company to unwind through cross-examination, so in 3 summary, we would move to strike all of Mr. Sterling's 4 testimony except page 1, line 1 through page 8, line 17, 5 and page 16, line 11 through page 21, line 11 in Docket 6 No. IPC-E-01-7 and IPC-E-01-11. 7 MS. NORDSTROM: Staff has no objection to 8 submitting only those portions which Mr. Ripley has set 9 out. That was Staff's intention and we had discussed this 10 previously and this in keeping with our discussion, so 11 Staff does move to only submit page 1, line 1 through 12 page 8, line 17 and page 16, line 11 through page 21, 13 line 11 and Rick's Exhibits Nos. 101 through 106 are found 14 within the testimony that I just set out, so we'd ask that 15 those six exhibits also be spread upon the record. 16 COMMISSIONER KJELLANDER: Well, then let's 17 make sure that everybody has that correct. Again for 18 reference, that's page 1 through page 8 to line 17 which 19 would be included; correct? 20 MS. NORDSTROM: Correct. 21 COMMISSIONER KJELLANDER: And then beginning 22 at page 16, line 11 to page 21, line 11 would also be 23 included. Everything else in that direct testimony would 24 be excluded from the 7/11 case and was I correct in hearing 25 that all of the exhibits would be included in 7/11? 292 CSB REPORTING STERLING (Di) Wilder, Idaho 83676 Staff 1 MS. NORDSTROM: Correct. 2 COMMISSIONER KJELLANDER: It seems like we 3 have some agreement on that, so the objection is -- we 4 agree and move forward. 5 (The following prefiled testimony of 6 Mr. Rick Sterling is spread upon the record.) 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 293 CSB REPORTING STERLING (Di) Wilder, Idaho 83676 Staff 1 Q. Please state your name and business address for 2 the record. 3 A. My name is Rick Sterling. My business address 4 is 472 West Washington Street, Boise, Idaho. 5 Q. By whom are you employed and in what capacity? 6 A. I am employed by the Idaho Public Utilities 7 Commission as a Staff engineer. 8 Q. What is your educational and professional 9 background? 10 A. I received a Bachelor of Science degree in 11 Civil Engineering from the University of Idaho in 1981 12 and a Master of Science degree in Civil Engineering from 13 the University of Idaho in 1983. I worked for the Idaho 14 Department of Water Resources from 1983 to 1994. In 15 1988, I received my Idaho license as a registered 16 professional Civil Engineer. I began working at the 17 Idaho Public Utilities Commission in 1994. During my 18 employment at the IPUC, I have attended the 1995 annual 19 regulatory studies program sponsored by the National 20 Association of Regulatory Commissioners (NARUC) at 21 Michigan State University, the 1995 Lawrence Berkeley 22 Laboratory Advanced Integrated Resource Plan (IRP) 23 Seminar, an advanced IRP course sponsored by EPRI 24 entitled Resource Planning in a Competitive Environment, 25 and a 1998 workshop on Pricing and Restructuring 294 STERLING, R (Di) 1 7/20/01 STAFF 1 Alternatives in a Changing Electric Industry sponsored by 2 the New Mexico State University Center for Public 3 Utilities. My duties at the Commission include analysis 4 of utility rate applications, rate design, tariff 5 analysis and customer petitions. 6 Q. What is the purpose of your testimony in this 7 proceeding? 8 A. The purpose of my testimony is to discuss the 9 adequacy of Idaho Powers long-term and short-term 10 planning process, changes that I believe need to be made 11 to the planning process, the role of IdaCorp's Risk 12 Management Committee in the planning process, and 13 recommendations on how the role of the Risk Management 14 Committee should be changed. 15 Q. What are the Commission's current electric 16 utility planning requirements? 17 A. Regulated electric utilities in Idaho are 18 required by Order No. 22299 to prepare IRPs and file them 19 biennially with the Commission. Integrated Resource 20 Plans include the following three basic elements: 21 1. A summary of existing hydroelectric, thermal 22 and Public Utility Regulatory Policy Act 23 (PURPA) generating resources, and a summary of 24 contract purchases and exchanges. 25 2. A summary of the utility's present load 295 STERLING, R (Di) 2 7/20/01 STAFF 1 situation and forecasts of possible future load 2 requirements. 3 3. A discussion of the utility's plan for meeting 4 all potential jurisdictional load over the 5 planning horizon. The discussion should 6 include references to expected costs, 7 reliability, and risks inherent in the range of 8 credible future scenarios. 9 Q. What is the purpose of an IRP? 10 A. The primary purpose of an IRP is to insure that 11 the utility considers all alternatives, both demand side 12 and supply side, for meeting expected loads in the future 13 at the lowest cost. The process of preparing an IRP also 14 insures that the full costs and risks associated with all 15 alternatives are considered. The process requires that 16 the utility seek input from its customers, interested 17 parties and from the Commission Staff. The process 18 itself and the submission of the written plan as an end 19 product, document the utility's planning and provide the 20 Commission and the public a window into the utility's 21 planning process as well as a forum for providing input. 22 Q. Can a utility deviate from its IRP? 23 A. Yes, in fact, a utility is expected to deviate 24 from its IRP when circumstances warrant. The Commission, 25 in Order No. 25260, adopted a policy regarding integrated 296 STERLING, R (Di) 3 7/20/01 STAFF 1 resource planning in which it stated the following: 2 The requirement for implementation of a plan 3 does not mean that the plan must be followed without deviation. The requirement of 4 implementation of a plan means that an electric utility, having made an integrated resource plan 5 to provide adequate and reliable service to its electric customers at the lowest system cost, 6 may and should deviate from that plan when presented with responsible, reliable 7 opportunities to further lower its planned system cost not anticipated or identified in new 8 existing or earlier plans and not undermining the utility's reliability. . . . the filing of 9 the plan does not constitute approval or disapproval of the plan having the force and 10 effect of law, and deviation from the plan would not constitute violation of the Commission's 11 orders or rules. The prudence of a utility's plan and the utility's prudence in following or 12 not following a plan are matters that may be considered in a general rate proceeding or other 13 proceeding in which those issues have been noticed. 14 15 The IRP represents a utility's long-term 16 plan for meeting load. Currently, utilities are required 17 to use a 10-year planning horizon. 18 Q. In Idaho Power's most recent IRP, how did the 19 Company indicate it would meet short-term deficits? 20 A. In Idaho Power's most recent IRP, the 2000 21 IRP filed in June 2000, the Company indicated that it 22 intended to meet short-term deficits by purchasing from 23 the market. The Company planned to have sufficient 24 resources in place to meet load under median water 25 conditions, but intended to meet deficits under low water 297 STERLING, R (Di) 4 7/20/01 STAFF 1 conditions with wholesale market purchases. 2 Under median water conditions and expected 3 loads, the 2000 IRP showed deficits beginning in the year 4 2000 of approximately 142 average MegaWatts (aMW) in 5 July, 86 aMW in August, and 88 aMW in December. Without 6 the addition of any new generation resources, deficits in 7 these months were expected to grow, and deficits in other 8 months were expected to appear as loads grew. Exhibit 9 No. 101 shows graphically the monthly energy 10 surplus/deficiency through 2010. To fully satisfy 11 expected deficits under median water conditions, Idaho 12 Power planned to purchase up to 250 aMW of energy in July 13 and August, and 200 aMW of energy in November and 14 December. 15 Q. If Idaho Power planned to rely on the market 16 even under median water conditions, what were its plans 17 under low water conditions? 18 A. Under low water conditions, the Company planned 19 to rely on the market to an even greater extent. Under 20 the low water scenario, the IRP projected substantial 21 deficits to begin immediately in the summer and winter 22 months. Exhibit No. 102 shows the monthly energy 23 surplus/deficiency under low water conditions. A deficit 24 of as much as 334 aMW appears as early as July 2000. 25 The monthly peak hour surplus/deficiency graph 298 STERLING, R (Di) 5 7/20/01 STAFF 1 also reveals how dependent Idaho Power was expected to be 2 under low water conditions as shown in Exhibit No. 103. 3 For the monthly peak hour, Idaho Power expected to be 4 deficit almost all of the months of the year. 5 Under low water, even with the purchase of 250 6 aMW in the summer (July and August) and 200 aMW in the 7 winter (November and December), the Company still 8 projected deficits as high as 264 aMW in May of 2000. 9 Exhibit No. 104 shows the Company's expected monthly 10 deficits, including planned seasonal purchases and new 11 resource additions. 12 Q. How did the low water scenario in Idaho 13 Power's IRP compare to what actually happened during the 14 past year? 15 A. Exhibit No. 105 compares actual surpluses and 16 deficits from June 2000 through May 2001 to the low water 17 scenario in the IRP. As the exhibit shows, deficits in 18 five of the twelve months were even greater than expected 19 under the low water scenario. 20 Q. It seems that Idaho Power's own IRP indicated 21 the degree to which the Company might have to rely on the 22 market this past year. Why then did Idaho Power incur 23 such high purchased power costs? 24 A. The level of reliance on the market during 25 the past year was, for the most part, expected given the 299 STERLING, R (Di) 6 7/20/01 STAFF 1 water conditions. Some months showed deficits even 2 greater than predicted under a low water scenario, while 3 in some months, water conditions were above the low water 4 condition and thus showed smaller deficits. What was not 5 expected, however, were the extremely high market prices. 6 The substantial planned reliance on the market combined 7 with the extremely high prices led to higher than 8 anticipated purchased power costs. 9 Q. How did Idaho Power respond to the high 10 market prices of the past year? 11 A. The Company responded in several different 12 ways. First, Idaho Power implemented buy-back programs 13 for their irrigation customers and for Astaris, their 14 largest industrial customer. In addition, the Company 15 made a decision to construct 90 MW of new gas-fired 16 generation at Mountain Home. Finally, the Company leased 17 25 MW of diesel-fired mobile generators and considered 18 plans to lease two additional 25 MW increments of mobile 19 generation. 20 Q. How did Idaho Power evaluate these resources 21 and programs? 22 A. For the most part, Idaho Power compared the 23 estimated costs of these resources and programs to the 24 prices they otherwise expected to pay to acquire power 25 from the market. 300 STERLING, R (Di) 7 7/20/01 STAFF 1 Q. Do you think Idaho Power's evaluations were 2 appropriate? 3 A. In most cases they were, but in some cases I 4 think more complete evaluations should have been done. 5 For example, the irrigation buy-back program is only 6 intended to last for the current season, so a comparison 7 to expected market prices was reasonable. Similarly, the 8 mobile generators have short-term leases that expire at 9 the end of the summer. The Astaris buy-back is a two- 10 year agreement, so a comparison with market alternatives 11 is possible but more difficult. The Mountain Home 12 project, on the other hand, is a project with an expected 13 life of 30 years. A comparison to current market prices 14 is not sufficient to determine the long-term cost 15 effectiveness of the project. As a long-term resource, 16 it should be compared to other long-term resource 17 alternatives. 18 19 (Page 8, line 18 through page 16, line 10 20 has been removed from the testimony by agreement of the 21 parties.) 22 23 24 25 301 STERLING, R (Di) 8 7/20/01 STAFF 1 2 3 4 5 6 7 8 9 10 11 Q. What process does Idaho Power follow for 12 short-term planning? 13 A. It appears that the short-term planning process 14 is not nearly as well defined as the long-term process 15 and that it depends somewhat on the circumstances. When 16 issues arise, those Company personnel most closely 17 associated with the issue perform the analysis, complete 18 the planning and carry out necessary actions. Decisions 19 about how to proceed however, appear to be made primarily 20 by the Risk Management Committee. For example, when 21 Idaho Power was faced with extremely high market prices 22 and poor water conditions this past winter and spring, 23 the Committee made decisions about which demand and 24 supply side alternatives to implement. Detailed program 25 and project plans were made by Idaho Power staff. 302 STERLING, R (Di) 16 7/20/01 STAFF 1 Q. Who are the members of the Risk Management 2 Committee, and what are their positions and 3 responsibilities within Idaho Power and IdaCorp? 4 A. The Risk Management Committee is made up of 5 the following members: 6 Darrel Anderson Vice President Finance, 7 Treasurer, Idaho Power Company 8 and IdaCorp 9 Jan B. Packwood President and Chief Executive 10 Officer, Idaho Power Company 11 and IdaCorp 12 Richard Riazzi Senior Vice President, 13 Generation and Marketing, Idaho 14 Power Company and IdaCorp 15 J. LaMont Keen Senior Vice President, 16 Administration and Chief 17 Financial Officer, Idaho Power 18 Company and IdaCorp 19 Jim Miller Senior Vice President, Delivery, 20 Idaho Power Company 21 Robert Stahman Vice President, Secretary and 22 General Counsel, Idaho Power 23 Company and IdaCorp 24 John Prescott Vice President Generation, Idaho 25 Power Company 303 STERLING, R (Di) 17 7/20/01 STAFF 1 Randy Hill President and Chief Executive 2 Officer, Ida-West Energy 3 An organizational chart showing the composition 4 of the Risk Management Committee is attached as Exhibit 5 No. 106. 6 Q. What is the purpose of the Risk Management 7 Committee? 8 A. The purpose of the Risk Management Committee 9 is to maintain general oversight over all of IdaCorp's 10 commodity trading and financial risk management 11 operations. As outlined in IdaCorp's Risk Management 12 Policy, the primary role of the Committee is to make 13 decisions regarding trading activities. The Risk 14 Management Policy does not outline any responsibilities 15 of the Committee with regard to acquisition of new 16 generating resources or implementation of short-term 17 demand side measures to meet load. 18 Q. Based on your investigation, does the Risk 19 Management Committee restrict its role to only that 20 outlined in the Risk Management Policy? 21 A. No, I believe the Risk Management Committee 22 has taken on a greatly expanded role. I believe the 23 original role of the Committee was to make decisions about 24 market transactions in order to manage risk to IdaCorp 25 shareholders. In fact, the Risk Management Committee was 304 STERLING, R (Di) 18 7/20/01 STAFF 1 originally formed in 1996 in response to the Company's 2 decision to enter into the non-regulated speculative 3 commodity trading business. However, a review of the 4 meeting minutes of the Committee over the past year shows 5 that the Committee has now evolved into a decision making 6 body for demand side and asset acquisition decisions, such 7 as how Idaho Power Company should respond to meet 8 short-term deficits and to minimize exposure to extremely 9 high market prices. In addition to the traditional 10 acquisition of energy from the market, the Risk 11 Management Committee considers alternatives to market 12 purchases, such as voluntary load reduction programs and 13 temporary generation resources. For example, based on 14 its meeting minutes, the Committee appeared to make final 15 decisions about whether Idaho Power should proceed with 16 the Astaris buy-back, the irrigation buy-back and the 17 installation of mobile generators. The Committee did not 18 appear to be involved in the selection of the Garnet 19 Project or the Mountain Home Project as long-term future 20 Company resources. 21 Q. Do you believe that it is appropriate for the 22 Risk Management Committee to take on this expanded role? 23 A. No, I do not. I believe that the Risk 24 Management Committee, given its apparent expanded role 25 and the composition of its membership, has created the 305 STERLING, R (Di) 19 7/20/01 STAFF 1 potential for serious conflicts of interest. What may be 2 best for the shareholders of IdaCorp may not be what is 3 best for ratepayers of Idaho Power Company. Because the 4 Committee is composed of some members who are not 5 officers of Idaho Power, and because the Committee 6 answers to the Board of Directors of IdaCorp, its first 7 allegiance is to its shareholders. Consequently, I believe 8 it is possible that its decisions are not always in the 9 best interests of ratepayers. 10 Q. Can you give an example of a conflict of 11 interest? 12 A. Yes, I can. Idaho Power's decision to lease 13 mobile generators was made by the Risk Management 14 Committee. While I am not judging the prudence of that 15 decision here, I am suggesting that the final decision to 16 proceed should not have been made by the Committee. Most 17 of the members of the Committee are officers of both 18 Idaho Power Company and IdaCorp, but some are officers of 19 only one. The president of Ida-West for example, should 20 not be involved in decisions about acquisition of new 21 generation by Idaho Power, even if the generation is only 22 temporary. Ida-West is an unregulated subsidiary of 23 IdaCorp whose business is building and operating new 24 generation projects. In theory, their project proposals 25 are supposed to compete with Idaho Power's own self-build 306 STERLING, R (Di) 20 7/20/01 STAFF 1 options. 2 Other situations could exist where the Risk 3 Management Committee may be willing to commit 4 shareholders to paying ten percent of increased power 5 supply costs as passed through by the PCA, in exchange 6 for the opportunity for shareholders to earn a much 7 greater unregulated return. A decision to rely on the 8 spot market instead of a term transaction could be one 9 example of such a conflict. If the decision were made by 10 Idaho Power, keeping the interests of ratepayers 11 foremost, a different decision might have been made. 12 13 (Page 21, line 12 through the end of the 14 testimony has been removed from the testimony by agreement 15 of the parties.) 16 17 18 19 20 21 22 23 24 25 307 STERLING, R (Di) 21 7/20/01 STAFF 1 (The following proceedings were had in 2 open hearing.) 3 COMMISSIONER KJELLANDER: With that, then, we 4 still have need for Mr. Sterling. 5 MS. NORDSTROM: Yes, and I tender him for 6 cross-examination. 7 COMMISSIONER KJELLANDER: Okay, and we will 8 begin with Mr. Richardson on this. 9 MR. RICHARDSON: Thank you, Mr. Chairman. We 10 have no questions for this witness. 11 COMMISSIONER KJELLANDER: Thank you, and now 12 let's move to Mr. Ripley with Idaho Power. 13 MR. RIPLEY: All right. 14 15 CROSS-EXAMINATION 16 17 BY MR. RIPLEY: 18 Q Directing your attention, Mr. Sterling, to 19 page 16 of your prefiled testimony, there you discuss the 20 decisions of the Risk Management Committee and their 21 interest in the operation of Idaho Power. Does it surprise 22 you that in a situation where the Company experiences both 23 poor water conditions and extremely high market conditions 24 that the chief financial officer of the Company would 25 desire to be included in any decisions as to the purchase 308 CSB REPORTING STERLING (X) Wilder, Idaho 83676 Staff 1 or sale of energy for Idaho Power Company, the utility 2 operation? 3 A No. 4 Q Wouldn't that be the same for Mr. Packwood on 5 page 17 of your testimony? Wouldn't he also have a higher 6 interest than one would assume would be normal because of 7 this extreme condition? 8 A Yes, I would assume so. 9 Q And without burdening the record, wouldn't 10 every one of these individuals have a higher and more 11 elevated interest in the Company's operations because of 12 the unique situation that it found itself in, i.e., bad 13 water, California situation and all the other litany of 14 things that you set out in your testimony? 15 A Yes, I think that would be true of all of 16 these people. 17 Q Now, on page 20, lines 12 through 14, you 18 start talking about the conflict of interest. Now, the 19 conflict of interest that you allude to are the leasing of 20 the mobile generators. Do you see that? 21 A Yes, I gave that as an example. 22 Q This decision did not occur during the months 23 of April 2000 through February 2001, did it? 24 A I can't say that I know exactly when that 25 decision was made. I didn't indicate in my testimony when 309 CSB REPORTING STERLING (X) Wilder, Idaho 83676 Staff 1 I thought the decision was made. 2 Q Well, but if you're using examples that have 3 occurred after February 28, 2001, do you think that's 4 appropriate in testing what the Company has done for the 5 period April 2000 through February 2001? 6 A Again, I used it as an example of a conflict 7 of interest and I don't think it's inappropriate to use an 8 example that could have just as easily occurred prior to 9 February 28th. I'm not saying that this didn't occur prior 10 to February 28th. I think it was in that same late 11 January/February time frame that Idaho Power made a number 12 of decisions about resource acquisitions, including mobile 13 generators. 14 Q But as to any of your criticisms, if the 15 event or the discussion surrounding that event occurred 16 after February 28th, 2001, then that would certainly not 17 be any indication of a conflict for the period before 18 February 28th, 2001, just intuitively? 19 A I would agree. 20 MR. RIPLEY: That's all the questions I have, 21 Mr. Sterling. Thank you. 22 COMMISSIONER KJELLANDER: Are there questions 23 from the Commission? 24 COMMISSIONER HANSEN: I have none. 25 COMMISSIONER KJELLANDER: Redirect. 310 CSB REPORTING STERLING (X) Wilder, Idaho 83676 Staff 1 MS. NORDSTROM: Thank you. 2 3 REDIRECT EXAMINATION 4 5 BY MS. NORDSTROM: 6 Q What was the point of you including that 7 specific example regarding mobile generators in your 8 testimony? 9 A I think the reason that I chose that as an 10 example was to illustrate what to me was probably one of 11 the most obvious conflicts of interest that I saw, which 12 was specifically that the president of Ida-West, an 13 unregulated Idaho Power subsidiary, was involved in making 14 decisions about resource acquisition and mobile generators 15 happened to be a resource acquisition-type decision that 16 they made. 17 Q And is it your contention that these 18 individuals sat on the Risk Management Committee during the 19 PCA period in question? 20 A Yes, that is my understanding. 21 Q So are you saying that similar conflicts of 22 interest could have existed during the last PCA period even 23 though this one may or may not have been included in the 24 PCA period? 25 A Yes. Again, I used this simply as an example 311 CSB REPORTING STERLING (Di) Wilder, Idaho 83676 Staff 1 of a possible conflict of interest that could occur because 2 of the composition and make-up of the Risk Management 3 Committee. My point was that I think there are potential 4 circumstances where there could be conflicts of interest 5 because of the way that committee was made up and Idaho 6 Power has since separated that into two separate committees 7 I think recognizing the possibility of at least in part 8 that there could be some conflicts of interest. 9 MS. NORDSTROM: Thank you. No further 10 questions. 11 COMMISSIONER KJELLANDER: Okay, Mr. Sterling, 12 thank you for your testimony. 13 (The witness left the stand.) 14 COMMISSIONER KJELLANDER: I think where we're 15 at today that this is probably as close as we're going to 16 come to a clean break, so unless anybody just desires to go 17 on for the next 25 to 30 minutes that we go ahead and break 18 for the day and I guess it would be our plan to start up 19 tomorrow at 9:30. Is that time amenable to everybody? All 20 right, why don't we go ahead and start at 9:00. 9:00 it is 21 and with that, then, we will go off the record for today 22 and rejoin tomorrow morning at 9:00. 23 (The Hearing recessed at 4:35 p.m.) 24 25 312 CSB REPORTING STERLING (Di) Wilder, Idaho 83676 Staff