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
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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
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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
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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.
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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.
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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
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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?
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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
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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
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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
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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
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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
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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,
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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.
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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
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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
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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.
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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 --
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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,
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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
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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.
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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
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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
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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.
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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.
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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 --
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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
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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
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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.
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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
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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
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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
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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
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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.
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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.)
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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,
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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
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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
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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
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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
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CSB REPORTING HOYD (X)
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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.
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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,
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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
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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?
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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?
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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?
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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?
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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.
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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
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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?
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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
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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?
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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
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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,
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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
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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
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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-
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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
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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
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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
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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
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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?
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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
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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?
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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
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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.
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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
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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
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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
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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.
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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?
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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
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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
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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.
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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,
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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.
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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
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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
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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
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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
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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?
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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.)
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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
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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
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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
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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
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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
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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
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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.
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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.)
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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.
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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
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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
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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
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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
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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.)
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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
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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
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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.
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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
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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.)
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