Puc8281.v1.doc

1 BOISE, IDAHO, TUESDAY, AUGUST 28, 2001, 9:30 A. M.

2

3

4 COMMISSIONER KJELLANDER: Well, good

5 morning, and this hearing will now be in order. This

6 is the time and place set by the Idaho Public Utilities

7 Commission for an evidentiary hearing in

8 Case No. IPC-E-01-7, which is referred to as in the

9 matter of the Idaho Power Company application for a

10 refundable energy emergency charge for the recovery of

11 extraordinary power supply expenses, and also a

12 hearing in Case No. IPC-E-01-11, which is referred to

13 as in the matter of the Idaho Power Company

14 application for authority to implement a power cost

15 adjustment rate for electric service from May 1st,

16 2001 through May 15th, 2002.

17 My name is Paul Kjellander and I'm a

18 member of the Commission. I'll be Chairing today's

19 hearing. To my right is Commissioner Dennis Hansen

20 and to my left is Commissioner Marsha Smith. The

21 three of us make up the entire Commission. For witnesses

22 that will be coming forward today, Commissioner Smith will

23 be swearing you in.

24 Now, this evidentiary hearing will deal

25 with the prudency of Idaho Power's 2000-2001 PCA pricing

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1 mechanisms, transmission and wheeling charges, weighted

2 average pricing for real-time purchases and the November

3 trading event, along with hedging activities. I'd like to

4 point out that the hearing related to Case No. IPC-E-01-16

5 will begin upon the conclusion of Cases 7 and 11, so let's

6 begin this morning by taking the appearances of the parties

7 and let's begin with Idaho Power.

8 MR. RIPLEY: Larry D. Ripley and Barton L.

9 Kline. Mr. Kline will be joining us tomorrow. He's

10 attending a personal matter today.

11 COMMISSIONER KJELLANDER: Thank you. Let's

12 move now to the PUC Staff.

13 MS. NORDSTROM: Lisa Nordstrom, Deputy

14 Attorney General, representing Commission Staff.

15 COMMISSIONER KJELLANDER: Early on I'd like

16 to remind everybody of the microphones. Thank you, and

17 let's see, Idaho Irrigation Pumpers Association, are they

18 present today? I don't see anyone present today. If they

19 do show up, we'll recognize them later.

20 Is there anyone from Astaris? Likewise, if

21 someone should show up representing them as an intervenor

22 in the case, we'll recognize that at the appropriate time.

23 How about the Idaho Industrial Customers of

24 Idaho Power Company?

25 MR. RICHARDSON: Thank you, Mr. Chairman.

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1 This is Peter Richardson of the firm Richardson and O'Leary

2 on behalf of the Industrial Customers of Idaho Power.

3 COMMISSIONER KJELLANDER: Thank you. For the

4 record, Idaho Rivers United, Idaho Rural Council and Mary

5 McGown have officially withdrawn from the proceedings. I'd

6 like to ask now if there's anyone here with the United

7 States Department of Energy and the answer to that is no.

8 Have I forgotten anybody who needs to be recognized for

9 purposes of cross-examination of witnesses?

10 MS. NORDSTROM: Mr. Chairman, just to

11 clarify, I spoke with Lawrence Gollomp from the Department

12 of Energy yesterday. He gave his apologies that he could

13 not attend due to some conflicts that he had in Washington

14 D.C. and indicated that he wanted to participate in these

15 cases even though he couldn't be present at the hearings.

16 COMMISSIONER KJELLANDER: Thank you for that

17 update. At this point are there any preliminary matters

18 that need to come before the Commission?

19 MR. RIPLEY: Yes, I have a couple,

20 Mr. Chairman.

21 COMMISSIONER KJELLANDER: Proceed.

22 MR. RIPLEY: I think you've answered the

23 first one, but I just wanted to make sure and that is I

24 assume that the Commission has allowed Idaho Rivers United,

25 Idaho Rural Council and Mary McGown to withdraw from this

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1 proceeding.

2 COMMISSIONER KJELLANDER: That's correct.

3 MR. RIPLEY: And we can delete them from our

4 service list. Thank you. Secondly, we had received a

5 pleading from the Idaho Irrigation Pumpers Association

6 withdrawing the testimony of Mr. Yankel. We have no

7 objection to that, but we have not yet seen an order from

8 the Commission and we're simply, I guess, curious as to the

9 status of Mr. Yankel's testimony.

10 COMMISSIONER KJELLANDER: Mr. Ripley, I think

11 I was perhaps anticipating that there may be someone from

12 that group show up today and do that officially before us.

13 If that doesn't happen, perhaps once we get to that point

14 because, as I understand it, I think you're doing your

15 direct first --

16 MR. RIPLEY: That's correct.

17 COMMISSIONER KJELLANDER: -- since there

18 would be no direct testimony presented by that association,

19 it therefore wouldn't be spread across the record and I

20 think when we get to the rebuttal testimony, we probably

21 would have to strike any reference that may have been made

22 with regards to comments by Mr. Yankel. I think that would

23 be the appropriate position to take at that time.

24 MR. RIPLEY: I'm a little confused. You took

25 one turn in the road there that I'm not sure I followed.

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1 We are assuming that no one has any objection to the

2 withdrawal of Mr. Yankel's testimony, therefore, it won't

3 be spread on the record, therefore, it won't be part of

4 this record and we'd like to know that as soon as possible

5 so that we either prepare or not prepare for

6 cross-examination.

7 COMMISSIONER KJELLANDER: Not a problem. I

8 think the point is that I haven't seen anything official

9 from that association.

10 MR. RIPLEY: Oh, I'm sorry, there was an

11 official --

12 COMMISSIONER KJELLANDER: And there's been

13 nothing discussed by this Commission in reference to that.

14 MR. RIPLEY: I see.

15 COMMISSIONER KJELLANDER: Okay, but I suppose

16 we could take a moment right now since there is something

17 official in front of us and make a decision on that.

18 MR. RIPLEY: I don't mean to push the

19 Commission. I mean, you can certainly do that --

20 COMMISSIONER KJELLANDER: That's not a

21 problem. This was the only document that I didn't have in

22 front of me and I think that that should make it very

23 simple to proceed. Oh, I probably did get one. I probably

24 haven't seen it and reviewed it officially and I don't

25 think there's any objection from the members of the

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1 Commission. There is not, so it is officially withdrawn.

2 MR. RIPLEY: Thank you. The next preliminary

3 issue may be my own blundering fault, I apologize to the

4 Commission, but I don't know what the record is in this

5 proceeding and if I could, I perceive that this proceeding

6 commences with the Commission's Order 28722 which

7 authorized a certain amount of the PCA that the Company had

8 requested and deferred $59 million for further proceedings

9 and that's what this proceeding is about.

10 I do not believe that the comments of the

11 parties that were filed under modified procedure, the

12 testimony that we prefiled in that original proceeding and

13 that part of the record is a part of this record, but I

14 need to know that so that I can make sure that I am

15 addressing everything that the Commission believes is part

16 of this record.

17 Now, obviously, the comments that were filed

18 on modified procedure gave rise to the fact that the

19 Commission set an evidentiary proceeding, but I do not

20 believe those comments are part of this record upon which

21 the Commission's deliberations as to the $59 million will

22 occur, but I need to know that I am not assuming something

23 that is not true or I'll do my best to make sure my record

24 is clear as to what I believe the Commission is deciding.

25 Hopefully, I've made the position of the Company clear.

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1 COMMISSIONER KJELLANDER: Let me see if there

2 are any comments from any of the other parties in reference

3 to that. Again, with the attorney representing the

4 Attorney General's Office and Staff?

5 MS. NORDSTROM: It was my understanding that

6 this issue had been raised earlier and it was the

7 Commission's decision at that point to defer a decision

8 until either the hearing or settling the record at some

9 point in the future, so the Staff has no objection to doing

10 it now. Whatever the Commission decides is fine with

11 Staff.

12 COMMISSIONER KJELLANDER: Thank you.

13 Mr. Richardson, any comments?

14 MR. RICHARDSON: No, Mr. Chairman.

15 COMMISSIONER KJELLANDER: Thank you. Well, I

16 don't think it's anything that we've discussed as a

17 Commission, so why don't we go off the record for just a

18 moment, I don't think it will take much longer than that,

19 and then we can get back with you on a decision, so we'll

20 go off the record for just a moment.

21 (Off the record discussion.)

22 COMMISSIONER KJELLANDER: Mr. Ripley, thank

23 you very much for raising that issue to our attention, we

24 appreciate that and would also like to say that the record

25 that has been built since that Order has been issued is the

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1 record that we'll move forward with today as it is

2 introduced today, so that would be all the testimony that

3 has been filed since that Order. Everything prior is on a

4 shelf someplace else.

5 MR. RIPLEY: Thank you, thank you.

6 COMMISSIONER KJELLANDER: Are there any other

7 preliminary matters that need to come before us?

8 MR. RIPLEY: Yes, there's two more and I

9 apologize, but I think it will speed up the process down

10 the road, I earnestly believe that, and that is we have

11 asked that the Commission take official notice of certain

12 orders and let me explain why. When you read the

13 Commission's rules, obviously, the Commission is entitled

14 to take official notice of its own orders and so what in

15 the world am I doing asking you to take official notice of

16 your own orders. There is an ongoing dispute as to what

17 the status of the record is if this matter were to be

18 appealed and there have been legions of briefs filed.

19 Since you are not a court of record, if you will, you can't

20 go somewhere and find your orders like you can find cites

21 of Idaho Supreme Court decisions, so some of the parties

22 have said the easiest way to do that so that all parties

23 are aware of the orders that various parties are relying

24 upon in a PUC proceeding is to ask that official notice be

25 taken of those orders, which obviously you can, so out of

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1 an abundance of caution, again, these same orders that I'm

2 asking you to take official notice of are also in the

3 testimony of Mr. Said, but I didn't want to get into the

4 box that Mr. Said is no lawyer and, therefore, he is

5 submitting orders of the Commission, et cetera, so the

6 simple way for me to do it, quite frankly, was to ask that

7 you take official notice of the orders that we've listed in

8 our request for official notice.

9 We've previously circulated those orders.

10 There's nothing preconceived or no evil intent on my part.

11 It's just that we believe those orders are important to the

12 Commission in arriving at its deliberations and we would

13 request that you take official notice of those orders and

14 they are, and I won't burden the record, Order No. 24308

15 issued in IPC-E-92-10; Order No. 24806 issued in

16 IPC-E-92-25; Order No. 26455 issued in Docket No.

17 IPC-E-96-5; Order No. 27516 issued in IPC-E-98-5; and after

18 this the IPC-E I'll delete even though they're all IPC-E

19 numbers, Order No. 27997 issued in 98-13; 28049 issued in

20 99-3; 28358 issued in E-00-6; 28522 issued in E-00-13; and

21 28596 issued in E-00-13; and then there is the report that

22 is the memorandum from Terri Carlock to the Commission

23 dated February 14, 2000 regarding Idaho Power energy

24 trading contracts and PCA. That I believe I do have to ask

25 you to take official notice of in strict compliance with

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1 the Commission's rules, so we would ask that you take

2 official notice of those orders for whatever they may be

3 worth when you are deliberating in this proceeding.

4 COMMISSIONER KJELLANDER: Thank you,

5 Mr. Ripley. Let me see if there are any comments from any

6 of the other intervenors today. Let's begin with

7 Mr. Richardson.

8 MR. RICHARDSON: Mr. Chairman, we have no

9 objection.

10 COMMISSIONER KJELLANDER: Thank you.

11 No objection?

12 MS. NORDSTROM: No objection from Staff.

13 COMMISSIONER KJELLANDER: Thank you. Well, I

14 believe that there's no objection also from any of the

15 members of the Commission, so your request is granted and

16 we'll take official notice of those.

17 MR. RIPLEY: Thank you, Mr. Chairman. I have

18 two and they are now supernits, but I will go through them

19 and that is when we originally filed our Exhibits 1 through

20 16, it was later called to my attention that we had

21 improperly labeled those exhibits in the lower right-hand

22 corner and that we failed to put the page numbers on them,

23 et cetera, so we have refiled Exhibits 1 through 16.

24 They're the identical exhibits that we filed in the direct

25 case. We just put better labeling in the lower right-hand

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1 corner and hopefully, we have not caused any confusion and

2 we have additional copies if any of the parties desire

3 them, and I sincerely apologize for not catching that

4 labeling problem when we originally filed our exhibits.

5 COMMISSIONER KJELLANDER: Okay, the

6 Commission is aware of that and I believe we all have that

7 in front of us today.

8 MR. RIPLEY: Thank you. I have extra copies

9 if --

10 COMMISSIONER KJELLANDER: It might not be a

11 bad idea, do you have those?

12 MR. RIPLEY: They're right underneath my

13 desk.

14 COMMISSIONER KJELLANDER: Why don't we get

15 them at a break.

16 MR. RIPLEY: Okay, I'll supply them to anyone

17 that desires during the break.

18 COMMISSIONER KJELLANDER: Thank you.

19 MR. RIPLEY: Now, lastly, just as a matter of

20 procedure when we get to the proceeding and that is the

21 order of cross-examination. We would suggest that the

22 order of cross-examination when Idaho Power Company is

23 submitting its direct case would be intervenor parties and

24 then Staff and then redirect by Idaho Power Company. When

25 Staff is presenting its testimony, we would suggest that

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1 the order of cross-examination be intervenors, Idaho Power

2 Company and then redirect by Staff. That does away, quite

3 frankly, with the issue of friendly cross-examination,

4 et cetera.

5 COMMISSIONER KJELLANDER: Could you for my

6 purposes, I'm a little slow with my pen this morning,

7 repeat that?

8 MR. RIPLEY: Certainly. When Idaho Power

9 Company is presenting its direct case or, for that matter,

10 its rebuttal that the order of cross-examination would be

11 the intervening parties, then Staff and then redirect by

12 Idaho Power Company.

13 COMMISSIONER KJELLANDER: Thank you.

14 MR. RIPLEY: And then you would flip it when

15 Staff is presenting their case. It would be, again,

16 intervening parties, then Idaho Power Company and then

17 redirect by Staff.

18 COMMISSIONER KJELLANDER: Thank you. Is

19 there any objection from any of the parties in the case?

20 MS. NORDSTROM: No.

21 MR. RICHARDSON: Yes, Mr. Chairman. The

22 problem with this is Mr. Ripley is trying to cure his

23 friendly cross and I think the Commission is well versed

24 with the case and can identify friendly cross if it's

25 happening. We do not plan to be very active in this case

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1 and to go first would put us at a disadvantage in terms of

2 understanding where the Staff is going and perhaps having

3 additional questions that may be sparked by the Staff's

4 questions, so I think the Commission is well equipped to

5 identify and prevent friendly cross without hamstringing it

6 in terms of the order of the cross-examination.

7 COMMISSIONER KJELLANDER: Are there further

8 comments? Response?

9 MR. RIPLEY: I think it makes a far more

10 orderly procedure if the parties that are prepared are

11 permitted to cross-examine last as opposed to those parties

12 that might be trying to learn on the job what the issues

13 are, but if Staff has no objection to there being this

14 follow-up cross-examination, I can't say that you're going

15 to prejudice the record. I certainly want to cross-examine

16 last when it comes to Idaho Power cross-examining Staff,

17 but as to the other, I thought it was just a more efficient

18 way to handle things, but that's why I brought it up now.

19 COMMISSIONER KJELLANDER: Thank you. What

20 I'd like to do is just go ahead and confer with the other

21 Commissioners, go off the record and come back and offer

22 you up our decision there.

23 (Off the record discussion.)

24 COMMISSIONER KJELLANDER: Mr. Ripley, I've

25 been reminded that it really is the prerogative, of course,

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1 of the Commission to decide what order we go in and to do

2 it as we see fit at that point in time as we move forward.

3 I guess at this point what I'd like to just let you know is

4 that with regards to Staff case, certainly, I think the

5 request for Idaho Power to move in the order that you've

6 requested makes sense and that was probably the route we

7 were going to go at any rate when we got to it.

8 As far as the order of cross-examination, I

9 don't see a problem with allowing Mr. Richardson's request

10 to go after Staff on that. He's already said he doesn't

11 anticipate a ton of questions and we'll see where we go

12 when we get there, but I think that certainly in reference

13 to your request for order for Staff's case, if you need

14 some clarification on that, we'll go ahead and allow that

15 to occur in the order that you described it, which as I

16 recall was intervenor, Idaho Power and then redirect by

17 Staff.

18 MR. RIPLEY: Thank you, Mr. Chairman.

19 COMMISSIONER KJELLANDER: All right, are

20 there other preliminary matters that need to come before

21 the Commission?

22 MR. RIPLEY: We would now like to make a very

23 brief opening comment, but it's very brief.

24 COMMISSIONER KJELLANDER: Certainly.

25 MR. RIPLEY: We are not going to say in these

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1 opening comments what the Company will prove or not prove

2 or what Staff's contentions are or what Staff's contentions

3 are not, but we do believe it is important to list what we

4 believe are major issues that the Commissioners are going

5 to have to look for the answers in this proceeding, and

6 that is that this proceeding, although certainly entailing

7 a large amount of paper and a significant amount of time,

8 is relatively simple, and that is as the Commission

9 considers the evidence in this proceeding, it must decide

10 essentially two ultimate issues: First, the trading

11 practices of Idaho Power Company as it relates to

12 51,234,902.

13 Both Idaho Power and the Staff have referred

14 to this trading practice. Now, that trading practice can

15 be broken down into two parts and that is we have day-ahead

16 transactions and real-time transactions and you will hear a

17 lot about that in the next couple of days. The day-ahead

18 transactions break down to roughly $47 million of the

19 amount that is currently deferred and the real-time pricing

20 is roughly $3.6 million of the $51.2 million in dispute.

21 The other major dispute is what the

22 Commission characterized and we've all picked up on and

23 that is the November transaction and that is, should Idaho

24 Power Company be permitted to recover the 7.9 million that

25 is the jurisdictional amount allocated to the Idaho

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1 jurisdiction or based upon the repricing as proposed by

2 Staff, should it lose the $7.9 million.

3 Now, the major issues as we see them that the

4 Commission we hope will ask questions and make sure that

5 they are comfortable is the issue of affiliated

6 transactions or the issue of what is the standard between

7 non-op/op, what rules were in place to handle the

8 transactions between the operating or the utility portion

9 of the business and the non-op portion of the business.

10 Obviously, I think that is going to be one of the major

11 issues that you'll have to address.

12 Secondly is, was the Company negligent when

13 it conducted its November transaction. Looking at the

14 facts, does the Commission believe that Idaho Power Company

15 did or did not do the correct practices when it related to

16 the transaction, and then the next issue that we believe

17 that you must address is this switch in the way that

18 pricing was performed for real-time transactions, so we

19 have day-ahead and we have real-time and the real-time, as

20 I have mentioned, is worth approximately $3.6 million of

21 the 59 million that you have ordered deferred.

22 Now, we also believe that the period of time

23 that's involved in Case 7/11 is important and that is the

24 period of time is for the PCA period April 1, 2000 through

25 February 28, 2001. The Commissioners will recall we filed

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1 early for our PCA. The Commission urged us to do so, we

2 did it on our own, we're not saying you urged us to do that

3 and therefore there's some duty that falls on your part,

4 but we're simply pointing out that the PCA period expired

5 February 28, 2001, so the $59 million we are talking about

6 is for the April 1, 2000 through February 28, 2001, and

7 although there are other discussions of time in this

8 proceeding, the relevant period of time that the

9 Commissioners should address, we hopefully urge, would be

10 what transpired during the period April 1, 2000 through

11 February 28, 2001 for the actions of the Company, was the

12 Company entitled or not entitled to rely upon certain

13 orders in place, et cetera.

14 Those we believe are the issues, and, again,

15 I'm not going to say what we're going to prove or not

16 prove. I don't mean this to be an advocate-type opening

17 comment but issues that we believe the Commissioners are

18 going to have to address and obviously, at the end I will

19 respond to those as we believe what the evidence shows, but

20 with that, we're ready to call our first witness.

21 COMMISSIONER KJELLANDER: Thank you,

22 Mr. Ripley, and if you'd like to, you can begin your case.

23 MR. RIPLEY: We call Mr. Said to the stand.

24

25

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1 GREGORY W. SAID,

2 produced as a witness at the instance of the Idaho Power

3 Company, having been first duly sworn, was examined and

4 testified as follows:

5

6 DIRECT EXAMINATION

7

8 BY MR. RIPLEY:

9 Q Mr. Said, would you state your full name for

10 the record, please?

11 A Gregory W. Said.

12 Q And your business address?

13 A 1221 West Idaho Street.

14 Q And, Mr. Said, did you have cause to be

15 prepared for this proceeding certain prefiled testimony

16 consisting of 21 pages?

17 A Yes, I did.

18 Q And is there also identified in your prefiled

19 testimony Exhibits 1 through 15?

20 A Yes.

21 MR. RIPLEY: Since the exhibits are

22 identified and noted in the prefiled testimony,

23 Mr. Chairman, I will not go through and identify the

24 exhibits again, if that is your pleasure.

25 COMMISSIONER KJELLANDER: Okay.

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Wilder, Idaho 83676 Idaho Power Company

1 Q BY MR. RIPLEY: And so, Mr. Said, if I asked

2 you the questions that are set forth in your prefiled

3 testimony, would your answers be the same today?

4 A Yes.

5 Q Do you have any corrections or deletions to

6 your testimony?

7 A No, I don't.

8 MR. RIPLEY: With that, we would ask that

9 Mr. Said's testimony be spread upon the record, that the

10 exhibits as premarked be taken under advisement by the

11 Commission subject to cross-examination and would tender

12 Mr. Said for cross.

13 COMMISSIONER KJELLANDER: Without objection,

14 they will be spread across the record.

15 (The following prefiled testimony of

16 Mr. Gregory Said is spread upon the record.)

17

18

19

20

21

22

23

24

25

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CSB REPORTING SAID (Di)
Wilder, Idaho 83676 Idaho Power Company

1 Q. Please state your name and business address.

2 A. My name is Gregory W. Said 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 Director of Revenue Requirement within the Pricing and

8 Regulatory Services Department.

9 Q. What is your educational background?

10 A. In May of 1975, I received a Bachelor of

11 Science Degree with honors in Mathematics from Boise State

12 University. In 1996, I completed the University of Idaho's

13 Public Utilities Executive Course in Moscow, Idaho. I have

14 also attended numerous seminars and conferences on

15 accounting and finance issues related to the utility

16 industry and have attended seminars and courses involving

17 public utility regulation.

18 Q. Could you please describe your business

19 experience with Idaho Power Company?

20 A. In 1980, after a few years of employment with

21 the State of Idaho, I became employed by the Resource

22 Planning Department of Idaho Power Company. In 1989, I was

23 offered and I accepted a position in the Company's Rate

24 Department. In 1994, I was asked to become the Meridian

25 District Manager for a one-year cross-training opportunity.

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SAID, DI 1
Idaho Power Company

1 In 1995, I returned to my position in the Rate Department.

2 In October of 1996 I was promoted to Director of Revenue

3 Requirement in the Pricing & Regulatory Services

4 department, a position I currently hold. I have presented

5 testimony before the Idaho and Oregon regulatory agencies

6 addressing various issues on numerous occasions.

7 Q. Please describe your experience with the

8 Company with regard to the Company's power supply costs.

9 A. My first responsibility with the Company in

10 1980 was to develop the Secondary Transactions Simulation

11 Model for use in determining the average net power supply

12 expenses associated with multiple hydro conditions as well

13 as the expenses associated with each hydro condition.

14 In December 1981, the Company applied for an

15 increase in its general revenue requirement in Case No.

16 U-1006-185. The Secondary Transactions Simulation Model

17 became the basis for determining the Company's normalized

18 net power supply expenses in that revenue requirement

19 proceeding.

20 In the next general revenue requirement

21 proceeding, Case No. U-1006-265, filed in September of 1985,

22 I was the Company's power supply witness providing direct

23 and rebuttal testimony as well as direct testimony upon

24 rehearing. At the same time, I was also the power supply

25 witness in the Company's Oregon jurisdictional filing.

54

SAID, DI 2
Idaho Power Company

1 In 1988, the Company applied for a temporary

2 rate increase because of drought conditions. Once again, I

3 was the Company witness addressing power supply issues.

4 In August of 1988, after nine years in the

5 Resource Planning Department, I was offered and I accepted

6 a position in the Company's Rate Department. With the

7 Company's application for a temporary rate increase in

8 1992, my responsibilities as a witness were expanded, but I

9 continued to be the Company's witness concerning power

10 supply expenses.

11 Q. When was the concept of a Power Cost

12 Adjustment (PCA) introduced?

13 A. In 1992, several parties urged the Company

14 and the Commission to implement some form of rate mechanism

15 for tracking power supply expenses. The Commission issued

16 Order No. 24308 (in Case No. IPC-E-92-10) stating that the

17 PCA issue would be analyzed in a formal proceeding initiated

18 for that purpose or in the course of the Company's next

19 general rate case. Exhibit 1 is a copy of Order No. 24308.

20 Q. As a result of Case No. IPC-E-92-10 and Order

21 No. 24308, how did the Company initially address the issue

22 of a Power Cost Adjustment?

23 A. During the IPC-E-92-10 proceeding, Mr.

24 Marshall, the Chief Executive Officer of Idaho Power

25 Company at that time, stated that the Company would conduct

55

SAID, DI 3
Idaho Power Company

1 an independent investigation of the complexities of a Power

2 Cost Adjustment, submit a report of Company findings, and

3 solicit constructive comments from the parties and

4 Commission Staff. Immediately after Order No. 24308 was

5 issued, Mr. Marshall assigned the Rate Department (now known

6 as Pricing and Regulatory Services) the responsibility of

7 developing a Power Cost adjustment methodology that would

8 be appropriate for Idaho Power Company if it was determined

9 that the Company should have such an adjustment.

10 My combined Resource Planning Department and

11 Rate Department experience uniquely qualified me to design

12 a Power Cost Adjustment that would impact customers rates

13 based upon changes in the Company's net power supply

14 expenses.

15 Q. Were you responsible for the PCA

16 investigation, in which the Company prepared a report

17 delineating an appropriate Power Cost Adjustment

18 methodology for Idaho Power Company?

19 A. Yes. On September 11, 1992, the Company

20 filed its "Power Cost Adjustment Analysis" report with the

21 Idaho Public Utilities Commission. At that time the

22 Company also distributed copies of the report to interested

23 parties. Exhibit 2 is a copy of that report.

24 Q. After distributing the report, did you

25 solicit comments from interested parties and Staff?

56

SAID, DI 4
Idaho Power Company

1 A. Yes. There were a number of conversations

2 about the Company's report with interested parties and

3 Staff. The conversations primarily involved clarification

4 of details within the report. In general, the parties

5 continued to be in favor of implementing a PCA for Idaho

6 Power Company.

7 Q. When did the Company apply for authority to

8 implement a Power Cost Adjustment in its Idaho jurisdiction?

9 A. The Company filed its application for

10 authority to implement a PCA in Idaho on November 24, 1992.

11 The Case number was IPC-E-92-25.

12 Q. Were you a witness in that case?

13 A. Yes, I was.

14 Q. In that proceeding, did you state what you

15 believe the primary objective of a Power Cost Adjustment

16 should be?

17 A. I stated that the primary objective of a

18 Power Cost Adjustment should be to provide a simple and

19 understandable mechanism that closely matches revenues

20 (resulting from rates) to the actual power supply expenses

21 incurred by the Company. I went on to state that the

22 objective could be met by identifying a variable component

23 of a customer's rate that reflects the variable expenses of

24 providing energy to serve the customers load. That

25 variable component would change as the cost of energy

57

SAID, DI 5
Idaho Power Company

1 changed. As a result, proper and understandable price/cost

2 signals would be sent to customers. When the Company's net

3 power supply expenses were higher, the Power Cost

4 adjustment would allow for the corresponding rate component

5 to be adjusted to a higher level. Conversely, when the

6 Company's net power supply expenses were lower, the rate

7 component would be lowered.

8 Q. Please give a general description of the

9 Power Cost Adjustment that you recommended in 1992.

10 A. The Power Cost Adjustment that I recommended

11 in 1992 provided for an annual adjustment in rates to be

12 made after April 1 each year based upon an estimate of the

13 projected April 1 through March 31 annual variable cost of

14 providing energy to firm loads. The power cost rate

15 component would remain in effect for one year (May 16

16 through May 15). Any difference between estimated and

17 actual annual variable costs of providing energy to firm

18 loads would be trued-up by deferring the actual monthly

19 expenses or revenues as they differed from the estimate.

20 The deferred expenses or revenues would be amortized in the

21 following annual power cost adjustment period (again May 16

22 through May 15 of the following year.)

23 Q. Does the general description of the Power

24 Cost Adjustment that you recommended in 1992 accurately

25 describe the Power Cost Adjustment that was approved by the

58

SAID, DI 6
Idaho Power Company

1 Idaho Commission?

2 A. The general description does describe the

3 Power Cost Adjustment that was approved by the Idaho

4 Commission with minor clarification. The general

5 description that I have provided suggests that 100 percent

6 of the deviations of actual PCA expenses from normalized

7 levels would be reflected in PCA rate changes. The

8 Commission, however, approved power cost rate adjustments

9 that reflected only 90 percent of the deviations of actual

10 PCA expenses from normalized levels except for deviations

11 in CSPP expenses which are reflected at 100 percent.

12 Q. What are the PCA components that the

13 Commission approved for inclusion as the annual variable

14 cost of providing energy to firm loads?

15 A. The PCA components are fuel expenses (FERC

16 account 501), purchased power expenses including

17 cogeneration and small power production (FERC account 555);

18 surplus sales revenues (FERC account 447) and Astaris

19 (formerly FMC) second block revenues.

20 Q. Are transmission and wheeling charges

21 included as a PCA component?

22 A. No. Transmission and wheeling revenues and

23 expenses are reported in FERC Account Nos. 456 and 565

24 respectively, which are not PCA FERC accounts.

25 Q. Initially, what information was required to

59

SAID, DI 7
Idaho Power Company

1 implement the PCA?

2 A. In order to implement the PCA, the Commission

3 quantified a base determination of PCA component values.

4 Normalized fuel expenses were quantified as $70,592,600.

5 Normalized purchased power expenses excluding CSPP were

6 quantified as $5,074,900. Normalized CSPP expenses were

7 quantified as $32,031,600. Normalized surplus sales

8 revenues were quantified as $42,833,500 and normalized FMC

9 secondary load revenue was quantified as $14,101,280. The

10 normalized net PCA expenses were $50,764,320, which was the

11 sum of fuel and purchased power expenses including CSPP

12 less the surplus sales and FMC secondary load revenues.

13 Q. Were any rate changes required to implement

14 the PCA?

15 A. Yes. Because FMC's secondary load was

16 interruptible and would be treated as a dispatchable

17 resource based upon variable cost, the second block rate

18 was re-established at 23 mills per kilowatt-hour. The FMC

19 primary block rates were also adjusted to ensure that the

20 overall FMC revenue remained the same.

21 Q. When did the Commission approve the use of a

22 PCA for Idaho Power Company?

23 A. The Commission issued Order No. 24806 in Case

24 No. IPC-E-92-25 approving a PCA for Idaho Power Company on

25 March 29, 1993. Exhibit 3 is a copy of Order No. 24806.

60

SAID, DI 8
Idaho Power Company

1 Q. How did the Commission describe the approved

2 PCA mechanism?

3 A. In Order No. 24806, the Commission stated:

4 "The mechanism we approve has the following

5 basic elements: It is based on annual

6 forecasted power supply costs; deviations

7 from predicted annual power supply expense

8 are deferred and trued-up in a subsequent

9 year; interest is accrued on deferrals; an

10 efficiency incentive shares variations in

11 power supply costs from a base case between

12 ratepayers and the Company on a 90-10 ratio;

13 a procedure to guard against rate shock is

14 included; power supply costs associated with

15 changes in load are factored out of the PCA;

16 rate changes mandated by the PCA are

17 recovered by an equal cents per kilowatt hour

18 allocation, and; proposed changes to the FMC

19 rate structure are approved."

20 Q. Have PCA computations ever been changed by

21 the Commission?

22 A. The PCA methodology still includes only fuel,

23 purchased power, surplus sales, and Astaris (formerly "FMC")

24 components. Deviations in expenses are still tracked at 90

25 percent with the exception of CSPP expenses that are tracked

61

SAID, DI 9
Idaho Power Company

1 at 100 percent. The load adjustment within the PCA has not

2 been modified.

3 Although the Commission has not changed the

4 basic PCA methodology, there have been four specific

5 computational changes to the PCA that I consider

6 significant. Three of the computational changes involved

7 correction or updating of PCA constants. Two of these

8 updates were the result of cases secondary to the actual

9 PCA proceedings. All four computational changes were

10 approved on a prospective basis.

11 Q. What was the first of the computational

12 changes to the PCA authorized by Commission order?

13 A. The first computational change was to correct

14 an erroneous PCA constant. This occurred during the

15 Company's 1996 annual PCA filing, which was offered as Case

16 No. IPC-E-96-5.

17 In that case, the Company noted that it had

18 erroneously filed the 1995 PCA calculation (and all previous

19 PCA calculations) using a system sales number rather than

20 the appropriate Idaho jurisdictional sales number. The

21 Company calculated the 1996 PCA using the Idaho

22 jurisdictional sales number and requested that this be

23 approved in addition to an adjustment to the true-up balance

24 by re-calculating the 1995 PCA with the appropriate value.

25 In their comments opposing parties argued that the Company

62

SAID, DI 10
Idaho Power Company

1 was attempting to use retroactive ratemaking for purposes

2 of the PCA. Additionally, parties commented that the

3 Commission, in Order 24806, had specifically limited the

4 time period for the true-up deferral, stating that the

5 differences between projected power supply costs and actual

6 power supply costs are to be deferred for later true-up and

7 those differences are to be accumulated during the 12-month

8 period that a specific PCA forecast would be in effect.

9 In response to Staff and intervener comments,

10 the Company suggested that a fair solution would be to

11 postpone the correction of this error until the following

12 year and prospectively. In Order No. 26455 (Exhibit 4) the

13 Commission found the following:

14 "The Commission has reviewed the filings of

15 record, including comments and Company

16 response. The Commission acknowledges that

17 Staff and ICIP support the Company

18 alternative proposal to defer implementation

19 of the change in true-up methodology until

20 next year. The Commission agrees that it is

21 more appropriate and reasonable to calculate

22 the true-up component of the PCA by dividing

23 the deferred expense balance by the Idaho

24 jurisdictional sales volume rather than the

25 normalized system firm load. We find that use

63

SAID, DI 11
Idaho Power Company

1 of normalized system firm load in prior

2 calculations has resulted in the Company

3 under recovering approximately $333,274 in

4 the 1993-94 true-up and $2,171,661 in the

5 1994-95 true-up. We agree with the Company

6 that both the utility and its customers

7 should be treated with fairness by this

8 Commission. We find that the alternative

9 proposal, offered by way of settlement, to

10 defer implementation of the change in true-up

11 methodology until next year's true-up

12 presents a fair, just and equitable result.

13 The resultant PCA rate adjustment from base

14 is -1.635 (mill/kWh) which we find includes

15 the accounting errors identified by Staff in

16 its comments and the related minor changes to

17 the calculation. We find the resulting PCA

18 adjustment to be fair, just and reasonable."

19 Q. When was the second computational change to

20 the PCA?

21 A. The second computational change to the PCA

22 was the updating of another PCA constant, which was

23 necessitated after the Company, and its largest customer,

24 FMC (now, Astaris) entered into a new contract. As a result

25 of the contract (dated December 31, 1997), the Company

64

SAID, DI 12
Idaho Power Company

1 requested that the PCA calculation reflect the new FMC

2 second block revenues as identified by the new contract.

3 At the time of the Company's 1998 annual PCA filing, a

4 joint application to approve the contract between the two

5 companies was pending before the Commission (Case No.

6 IPC-E-97-13). No parties were in opposition to the new

7 contract when the Company filed its annual PCA case (Case

8 No. IPC-E-98-5.) The Commission issued Order No. 27516

9 (Exhibit 5) approving the Company's request to have the

10 current FMC second block revenues reflected in the PCA

11 forecast equation. Once again the computational change was

12 prospective.

13 Q. In Case No. IPC-E-98-5, did the Company

14 identify another PCA constant that might require updating?

15 A. Yes. In the 1998 filing, the Company noted

16 that the QF constant in the PCA calculation was not

17 reflective of actual costs and should be reviewed in the

18 near future, but did not request any changes to the 1998 QF

19 quantification.

20 Q. Was further action taken on this issue?

21 A. Yes. As a result of a separate filing, Case

22 No. IPC-E-98-13, the Company requested a change to the then

23 insufficient QF constant. The third computational change

24 approved in Order No. 27997 (Exhibit 6) was to update the QF

25 constant previously identified during the 1998 PCA filing.

65

SAID, DI 13
Idaho Power Company

1 Q. What drove the need for a fourth

2 computational change to the PCA?

3 A. The fourth computational change occurred as a

4 result of the Financial Accounting Standards Emerging

5 Issues Task Force determination (EITF-98-10). On March 18,

6 1999, the Company notified the Commission of the accounting

7 changes (Exhibit 7 - Mr. Gale's Letter to Ms. Miller.)

8 Confirmation of the notification letter was received on

9 April 7, 1999 (Exhibit 8 - Ms. Miller's Letter to Mr. Gale.)

10 In Order No. 28049 (Exhibit 9) issued in the 1999 PCA case

11 (Case No. IPC-E-99-3) the Commission directed the Staff to

12 coordinate with the Company and other interested parties to:

13 "determine, informally, how best to address

14 the issue. Those parties might consider

15 conducting a workshop. If necessary, any or

16 all of them are free to petition this

17 Commission to initiate a formal case.

18 Regardless, we expect that some written work

19 product will ultimately emanate from the

20 efforts of the parties containing an analysis

21 of the issue and a recommendation regarding

22 what action, if any, is needed by this

23 Commission."

24 A workshop was held at the offices of Idaho

25 Power Company in Boise on September 23, 1999 to address the

66

SAID, DI 14
Idaho Power Company

1 issue. Following the workshop, Staff generated a

2 memorandum (Exhibit 10 - Memorandum dated February 14,

3 2000) that summarized the outcome of the workshop, which

4 was presented to the Commission. In Order No. 28358

5 (Exhibit 11) issued as a result of the Company's 2000

6 annual PCA filing, (Case No. IPC-E-00-6) the Commission

7 acknowledged the Staff Memorandum addressing the accounting

8 change concerns raised by opposing parties and their

9 request to initiate a separate proceeding to review the

10 current method for compensating Idaho Power and its

11 shareholders for operating Idaho Power and stated that this

12 request was "outside the scope of this proceeding." New

13 accounting rules were established which included guidelines

14 to separate "energy contracts" from "energy trading

15 contracts" for purposes of accounting, including accounting

16 of revenues and expenses for the annual PCA.

17 Q. What additional changes did the Company make

18 that related to the accounting issue?

19 A. The Company filed an application with the

20 Commission for approval of an agreement for electricity

21 supply and management services between Idaho Power Company

22 and IDACORP Energy Solutions, LP. (See Exhibit 12, Notice

23 of Application, Case No. IPC-E-00-13.) This agreement

24 would further remove the "non-operating transactions" (e.g.

25 wholesale power market sales that do no involve sales from

67

SAID, DI 15
Idaho Power Company

1 the system resources and are not related to balancing

2 system loads and resources) from the Company's accounting.

3 A Stipulation was issued (Exhibit 13) which specifically

4 defined the terms under which the two entities (Idaho Power

5 Company and IDACORP Energy Solutions, LP) would operate

6 within the Agreement for Electricity Supply and Management

7 Services. The Commission, in Order No. 28596, Case No.

8 IPC-E-00-13 (Exhibit 14) which followed the Company's

9 issuance of the signed Stipulation, found that:

10 "public interest was well served by the

11 procedure adopted in this case, i.e. the two

12 public workshops and an opportunity for

13 written comments. The resultant Stipulation,

14 we find, has improved the underlying

15 Agreement and dispensed with the necessity of

16 further proceedings. IDAPA 31.01.01.204. We

17 note that the ICIP, while not signing the

18 Stipulation, expressly states that it does

19 not object to the continued use of Modified

20 Procedure in this case. We accept the case

21 as fully submitted and find that we have an

22 adequate record to fully consider the issues

23 presented by the Company's Application.

24 Regarding the IPCo/IES Agreement, we find

25 that the Agreement establishes a reasonable

68

SAID, DI 16
Idaho Power Company

1 and transparent structure for prioritizing,

2 protecting and serving native load

3 requirements. We are convinced that the

4 Agreement gives the Company's native load

5 customers priority and the economic use and

6 dispatch of Company generation resources,

7 transmission and distribution facilities. In

8 distinguishing between operating and non-

9 operating transactions, it also provides a

10 reasonable means of assuring that the

11 Company's native load customers are not

12 saddled with those risks unrelated to

13 providing regulated utility services."

14 Q. Has the Commission ever issued an order,

15 which expands the accounts that are to be included in the

16 Company's PCA methodology?

17 A. No.

18 Q. Does the Commission require that the Company

19 file a monthly PCA true-up report?

20 A. Yes, IPUC Order 24806 requires Idaho Power to

21 file a PCA true-up report monthly and at the end of a PCA

22 year the final monthly true-up report is used as an Exhibit

23 in the Company's annual PCA filing. Exhibit 15 is a

24 representative copy of the monthly true-up report provided

25 to the Commission in Case No. IPC-E-01-07. The report

69

SAID, DI 17
Idaho Power Company

1 tracks the actual PCA component revenues and expenses

2 compared to the previous year's projections, month by month

3 with the differences accumulated in a deferred account (FERC

4 Account 182.3). Carrying charges are then applied monthly.

5 Q. Are the utility's PCA revenues and expenses

6 reported on a system basis in the PCA report?

7 A. Yes, the report begins with system values for

8 PCA revenues and expenses, which are adjusted to reflect

9 the efficiency incentive (90% sharing) and the Idaho retail

10 jurisdictional percentage (85% allocation). The only

11 exception as previously stated is the efficiency incentive

12 applied to Cogeneration and Small Power Producers payments

13 that is 100% before it is jurisdictionally allocated.

14 These sharing percentages and allocation factors are set

15 forth in Order 24806.

16 Q. Please describe in detail the computations

17 set out in the PCA true-up report.

18 A. Referring to Exhibit 15, lines 5-7 quantify

19 the anticipated revenues to be derived from PCA rates

20 resulting from the previous PCA year forecast of net power

21 supply expenses. Lines 10-13 quantify and value the

22 difference in actual total system firm load and normalized

23 total system firm load as set in the last general revenue

24 requirements case. Lines 16-36 quantify the difference

25 between actual fuel expense (FERC Account 501), non-firm

70

SAID, DI 18
Idaho Power Company

1 purchased power expense (FERC Account 555), less surplus

2 sales revenue (FERC Account 447) and Astaris second block

3 revenue (FERC Account 442) as compared to base levels for

4 the same items as set in the last general revenue

5 requirements case. Lines 38-47 quantify the difference in

6 actual cogeneration and small power purchased power (FERC

7 Account 555) and the base level set in the last general

8 revenue requirements case. Lines 52-58 reflect the monthly

9 increment and the accumulated balance of the total PCA

10 component expenses to be deferred. Lines 62-68 reflect the

11 monthly computation of interest (carrying charge) and the

12 accumulated interest balance. Line 70 reflects the total

13 balance of PCA component expenses deferred including

14 interest to be recovered in the next PCA rate case.

15 Q. What is the source of the total system

16 revenues and expenses contained in the monthly report?

17 A. The Financial Accounting Department obtains

18 this information monthly from the actual books and records

19 of the Company.

20 Q. The Commission has ordered the deferral of

21 $51,234,902 relating to what the Commission refers to as

22 issues concerning trading practices. Please explain your

23 understanding of the derivation of the $51,234,902. The

24 Company booked $185,649,095 in the PCA true-up account.

25 A. As I understand the "trading practices"

71

SAID, DI 19
Idaho Power Company

1 issues, the Commission has deferred approval of booked

2 expenses amounting to $51,234,902, which are related to the

3 pricing of transactions involving certain day-ahead, and

4 real-time power purchases for the utility operating system.

5 Ms. Hoyd has informed me that these purchases were priced

6 as required by IPUC Order 28358 and the Report to the Idaho

7 Public Utilities Commission on Workshop Concerning Energy

8 Trading Contracts and Power Cost Adjustment dated February

9 14, 2000. Staff re-priced those transactions using a new

10 methodology contending that the actual cost for those

11 purchases should be reduced. Based upon this new

12 methodology, staff reduced the total booked true-up amount

13 of $185,649,095 by $51,234,902.

14 Q. The Commission has also ordered the deferral

15 of $7,976,701 relating to what the Commission refers to as

16 issues concerning the "November Transaction". Please explain

17 your understanding as to the derivation of the $7,976,701.

18 A. The $7,976,701 relating to the "November

19 Transaction Issue" is a Staff computation of cost savings

20 the Company could have realized had it timed a purchase

21 transaction for the system differently. Mr. Anderson's

22 testimony discusses in detail the events surrounding this

23 transaction. The $7,976,701 amount is based upon the

24 assumption that the purchase should have taken place when

25 the prices were lower. Based upon this quantification the

72

SAID, DI 20
Idaho Power Company

1 total true-up amount of $185,649,095 was reduced by

2 $7,976,701, resulting in a reduction of the PCA true-up

3 balance by this amount.

4 Q. In your opinion, are these two adjustments

5 appropriate deductions from the true-up amount of

6 $185,649,095?

7 A. No, based upon my understanding of the PCA

8 methodology and the explanations provided by Mr. Anderson,

9 Ms. Hoyd and Mr. Gale, the $59,211,603, which has been

10 deferred, should be approved by the Commission for

11 inclusion in the PCA true-up.

12 Q. Does this conclude your testimony?

13 A. Yes, it does.

14

15

16

17

18

19

20

21

22

23

24

25

73

SAID, DI 21
Idaho Power Company

1 (The following proceedings were had in

2 open hearing.)

3 COMMISSIONER KJELLANDER: And we would then

4 move first to Ms. Nordstrom.

5 MS. NORDSTROM: I'm sorry, perhaps I

6 misunderstood, did Mr. Ripley ask earlier that the

7 intervenors would go first or that Staff would go first?

8 COMMISSIONER KJELLANDER: It doesn't matter,

9 I'm going to you.

10 MS. NORDSTROM: That's fine.

11

12 CROSS-EXAMINATION

13

14 BY MS. NORDSTROM:

15 Q Good morning.

16 A Good morning.

17 Q Do you have your testimony in front of you?

18 A I do.

19 Q Thank you. On page 5, lines 17 through 21,

20 you stated that the primary objective of a power cost

21 adjustment should be to closely match revenues to the

22 actual power supply expenses incurred by the Company.

23 Isn't it true that the use of the market index prices is a

24 change to the PCA as originally adopted?

25 A No, I don't believe so. The power cost

74

CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company

1 adjustment has included purchased power as a component

2 since its origination and those purchases have been made at

3 market prices since the beginning.

4 Q Why isn't it a change from including actual

5 expenses incurred in the PCA to including power at an index

6 price as a surrogate for actual expenditures?

7 A I guess my reaction to your use of the word

8 "surrogate" is that market, the market index is the market

9 price that the Company encountered for those purchases.

10 Q On page 7, beginning on line 20, you discuss

11 transmission and wheeling. Please explain the type and

12 degree of transmission and wheeling activity when the PCA

13 was first implemented.

14 A Essentially when the PCA was first

15 implemented, transmission and wheeling, both expenses and

16 revenues, were fairly constant from year to year and so the

17 consensus of all of the parties involved was that those

18 expense and revenue accounts that did not vary greatly with

19 purchases or sales would not be components included in the

20 power cost adjustment.

21 Q These were activities for utility operations;

22 correct?

23 A That's correct.

24 Q You were saying that they didn't vary much.

25 Are you saying that the amount was relatively stable?

75

CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company

1 A Yes.

2 Q Does that also mean that the price levels

3 seen were relatively stable?

4 A The price levels for wheeling and

5 transmission were fairly stable, yes.

6 Q Were the costs and benefits included in base

7 utility customer rates?

8 A Yes, they were.

9 Q Did Order No. 888 of the Federal Energy

10 Regulatory Commission change the usage and degree of

11 transmission and wheeling charges?

12 A Yes.

13 Q What transmission costs and revenues

14 associated with system or non-system purchase and sales

15 transactions currently are included in the PCA?

16 A There have been no adjustments to the

17 inclusion of transmission and wheeling revenues or

18 expenses. Those are accounts that are still excluded from

19 the power cost adjustment.

20 Q Aren't transmission expenses and revenues

21 built into base rates?

22 A Yes, I think I stated that before.

23 Q Are transmission and wheeling revenues now

24 greater than they were in the last general rate case?

25 A I haven't reviewed those accounts, but I

76

CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company

1 would assume that both revenues and expenses are higher

2 than what may have been the case in the last general

3 revenue requirement proceeding.

4 Q Will you accept that the amount of

5 transmission and wheeling revenues included in base rates

6 in the IPC-E-94-5 rate case was approximately

7 $2.7 million?

8 A Yes.

9 Q Are you familiar with the procedure to guard

10 against rate shock?

11 A I don't know which procedure you're referring

12 to, no.

13 Q I believe that's your Exhibit 3, Order No.

14 24806.

15 A I guess I had never heard that Order referred

16 to as a procedure for prevention of rate shock.

17 Q Is that discussed within this Order?

18 A Maybe you could point me to a page.

19 Q Specifically, page 9, line 13.

20 MR. RIPLEY: I'm sorry, could you give that

21 page number again?

22 MS. NORDSTROM: Page 9.

23 THE WITNESS: Of Exhibit 3?

24 Q BY MS. NORDSTROM: Yes.

25 A If I've counted my lines correctly, that

77

CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company

1 statement is, "Finally, we find that a forecast-based PCA

2 that trues-up to actual, as proposed by Idaho Power,

3 eliminates the possibility of the Company over-recovering

4 its power supply costs."

5 Q Are you familiar with the concept that the

6 rate change was limited to a 7 percent increase?

7 A My recollection of the Order in that regard

8 was that if a power supply cost increase was going to be

9 greater than 7 percent that it would require additional

10 review from the Commission to determine if that was

11 appropriate.

12 Q Is it accurate to state that the average

13 percent increase above existing rates granted in 2000 for

14 the 1999-2000 PCA year was about 8 percent?

15 A Eight percent? I think that's low, from my

16 recollection. In 2000, last year's?

17 Q For the '99-2000 PCA year.

18 A That may be correct.

19 Q Is it accurate to state that the average

20 percent increase above existing rates granted for the

21 2000-2001 PCA year was above 30 percent?

22 A I believe that's correct.

23 Q Is it accurate to say that the granting of

24 increases greater than 7 percent is a recognition of

25 changing conditions?

78

CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company

1 A I believe so, yes.

2 Q Isn't this a change from the procedure

3 implemented?

4 A No. Again, the Commission in its original

5 Order stated that increases greater than 7 percent would

6 receive additional review to see if they were appropriate

7 and in both of those instances they did.

8 Q From your understanding of that Order

9 granting that PCA increase, how was that change justified?

10 A The Commission reviewed the nature of why

11 expenditures had been higher in those years. In the 2000

12 case, the condition had moved from a hydro condition

13 that had been significantly above an average hydro

14 condition to a condition that was significantly below

15 an average condition and so the rate increase for that

16 year moved from a good water condition to a poor water

17 condition and, therefore, justified an increase of greater

18 than 7 percent.

19 With the Company's application this year,

20 market price was the primary driver of the extraordinary

21 costs and we'd seen prices at unprecedented levels which

22 the Commission recognized as a rationale for approving a

23 greater than 7 percent increase.

24 Q So isn't it true that the Commission deviated

25 from the original procedure regarding the 7 percent rate

79

CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company

1 increase limit after the PCA year ended when reasonable and

2 justifiable explanations were presented?

3 A No, they did not deviate from the procedure

4 that had been established. Again, the procedure called for

5 them to review increases of greater than 7 percent to see

6 if they were reasonable and in both instances they did.

7 Q On page 17, lines 14 through 17, you state --

8 COMMISSIONER KJELLANDER: Page 17 of the

9 direct testimony or are you still with the exhibit?

10 MS. NORDSTROM: Of the direct.

11 COMMISSIONER KJELLANDER: Thank you.

12 Q BY MS. NORDSTROM: On page 17, you state that

13 the Commission hasn't expanded the accounts included in the

14 Company's PCA methodology. Are you aware that Order No.

15 28775 in Case No. AVU-E-01-1 for Avista approved the

16 expansion of accounts included in Avista's PCA?

17 A I was not aware of that.

18 Q On page 14, lines 8 and 9, you made reference

19 to a letter sent by Stephanie Miller to Ric Gale regarding

20 accounting changes necessary to comply with the Financial

21 Accounting Standards Emerging Issues Task Force's

22 determination. This letter is marked as Exhibit 9 in your

23 testimony. Did this letter advise Idaho Power that the

24 Commission reserves judgment on ratemaking issues related

25 to the exclusion of transactions from the PCA?

80

CSB REPORTING SAID (X)
Wilder, Idaho 83676 Idaho Power Company

1 A Yes, and I can quote the sentence, "It does

2 not take exception to the described accounting changes but

3 reserves judgment on ratemaking issues related to the

4 exclusion of these transactions from the PCA."

5 Q And isn't ratemaking the purpose of this

6 hearing today?

7 A The purpose of this, of the hearing today, is

8 to decide whether or not the Company incurred expenditures

9 on behalf of its customers, properly accounted for those

10 expenditures and did so in compliance with Commission

11 orders.

12 Q Page 20 of your testimony describes a

13 conversation that you had with Sharon Hoyd. You state:

14 "Ms. Hoyd has informed me that these purchases were priced

15 as required by IPUC Order 28358." Are you familiar with

16 this PCA Order which is included with your testimony as

17 Exhibit 11?

18 A Yes, I've read the Order.

19 Q Where in this Order is the Company directed

20 that the Mid-C be used for real-time and day-ahead

21 transactions?

22 A Those specific words probably do not appear

23 in the Order. The nature of my statement here is that

24 purchases that are made on behalf of our customers that

25 flow through Account 555 are to be priced at market prices.

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1 Q So would it be fair to say that the

2 Commission approved the filing but did not adopt the Mid-C

3 pricing mechanism?

4 A I'd have to look at that Order a minute. If

5 I could ask a clarifying question, when you are talking

6 about Mid-C prices, are you talking about day-ahead or

7 real-time?

8 Q Either.

9 A Okay. With regard to that case, the Order on

10 page 3 has a statement from the Staff that says, "...the

11 methods, representations and calculations are generally

12 correct and comply with the Commission's PCA Orders," and

13 the Commission recognized that the computations that were

14 included in that power cost adjustment case were correct

15 and complied with Commission orders, so the pricing

16 according to Mid-C indexes that were included in that case

17 were indeed recognized by the Commission as appropriate.

18 Q Did you see any mention of this approved

19 filing as continued authority for future years?

20 A Absolutely.

21 Q Can you point to that portion of the Order

22 that indicates that?

23 A I think I just did. On page 3, it's under

24 Commission Findings and it's the third full paragraph that

25 states: "Staff reviewed Idaho Power's application and

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1 supporting documentation and concluded that the methods,

2 representations and calculations are generally correct and

3 comply with Commission PCA Orders."

4 Q How does that talk about future approval?

5 A Until we have an order telling us to do

6 methodology differently than what we've done, the Company

7 relies on Commission orders that are in existence in terms

8 of the future. We don't feel that the Company has the

9 right to arbitrarily and unilaterally deviate from what the

10 Commission has approved in the past.

11 Q But you understand that if rates are not just

12 and reasonable that changes would have to be made, correct,

13 if the Commission were to make that determination?

14 A If the Commission were to determine that

15 rates were unjust and unreasonable, that's correct.

16 Q On page 21, lines 7 through 11, you

17 acknowledge that your assessment of the inclusion of the

18 $59 million in the PCA true-up was based on explanations

19 provided by Mr. Anderson, Ms. Hoyd and Mr. Gale. Can you

20 make the same assessment based on your independent

21 knowledge?

22 A Yes, I can.

23 Q And what is your independent knowledge that

24 you are basing that assessment on?

25 A I was the Company witness at the time that

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1 the power cost adjustment was proposed. Included in my

2 exhibits are Exhibit 2 which is the Company's original

3 evaluation of power cost adjustment methodologies which I

4 authored. I've been a witness in all but possibly two

5 power cost adjustment proceedings since its origination.

6 I've been involved in discussions with the Staff and

7 hearings with the Commissioners since the beginning of the

8 power cost adjustment and so I feel that I have some

9 understanding of the way it operates and is intended to

10 operate.

11 Q Then why did you need explanations by Mr.

12 Anderson, Ms. Hoyd and Mr. Gale?

13 A What Mr. Anderson explained to me was the

14 process that the Risk Management Committee had gone through

15 in deciding when to make forward purchases and when not.

16 Those judgment calls have been a part of Company operations

17 since the beginning of the time that the power cost

18 adjustment was in place and my discussions with Mr.

19 Anderson were to confirm that the decision process that he

20 went through and that the Risk Management Committee went

21 through were similar to what had been done in the past.

22 Ms. Hoyd is involved in the accounting of the

23 costs associated with purchases and sales and my

24 discussions with her were along the lines of whether or not

25 the expenses and revenues that were recorded were

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1 consistent with the way that the pricing is normally done

2 for those transactions, and Mr. Gale has been involved with

3 some of the more recent power cost adjustment transactions

4 as well as the evaluation of ultimately moving those, the

5 non-operating transactions to an affiliate.

6 Q But these were items that you didn't

7 understand without help from others?

8 A I don't follow the accounting and I'm not a

9 member of the Risk Management Committee, so to the extent

10 that they can broaden my knowledge, yes, I did talk to them

11 to make sure I had a full understanding.

12 Q On page 21 of your testimony, you also

13 discuss the appropriateness of two Staff recommended

14 adjustments and conclude that they're inappropriate in part

15 based on your understanding of the PCA methodology. Would

16 an adjustment in the true-up amount be appropriate if it is

17 found that the costs included in the deferral balance were

18 not actually incurred?

19 A Absolutely.

20 Q So would you agree that under the existing

21 PCA methodology Staff has the right to review, question the

22 validity and even object to costs requested for recovery?

23 A I think the Staff does have the right to go

24 in and that's their job to see that the expenditures

25 included in the Company's accounting books are correct and

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1 accurate and I believe they so stated in the emergency

2 energy charge this year. What they've now done in my

3 opinion is gone back and said that the pricing of those

4 transactions should be done using a different pricing

5 system than has been used in the power cost adjustment in

6 the past.

7 Q Would you agree that the power supply

8 expenses at issue in this case are associated with the

9 true-up portion of the PCA mechanism and are an after the

10 fact request for cost recovery?

11 A Right, that's the nature of the power cost

12 adjustment. It has a forward-looking piece and a true-up

13 piece that has been approved. In the original case, the

14 issue of retroactive ratemaking was discussed extensively

15 and it was decided that a true-up of the forecast, in

16 essence, the previous year's forecast, would be appropriate

17 in a power cost adjustment.

18 MS. NORDSTROM: May I have a moment to confer

19 with those seated with me to see if we have further

20 questions?

21 COMMISSIONER KJELLANDER: Sure, we'll go off

22 the record.

23 (Pause in proceedings.)

24 COMMISSIONER KJELLANDER: We'll go back on

25 the record.

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1 Q BY MS. NORDSTROM: Back in about the second

2 question I asked and the question was why isn't a change

3 from including actual expenses incurred in the PCA to

4 including power at an index price as a surrogate for actual

5 expenditures, you mentioned that the Company paid the price

6 encountered and our question is, does this mean that the

7 power was bought at the index price, is that the market

8 price?

9 A The Mid-C index is the market price, yes.

10 Q Was that the price paid by the Company for

11 these purchases?

12 A Yes.

13 MS. NORDSTROM: Thank you. Staff has no

14 further questions.

15 COMMISSIONER KJELLANDER: Thank you. We'll

16 move now to Mr. Richardson.

17 MR. RICHARDSON: Thank you, Mr. Chairman.

18

19 CROSS-EXAMINATION

20

21 BY MR. RICHARDSON:

22 Q Good morning, Mr. Said.

23 A Good morning.

24 Q You were involved in the development of the

25 PCA, were you not?

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1 A Yes.

2 Q In fact, you essentially developed the

3 Company's PCA recommendation; correct?

4 A Yes.

5 Q In your direct testimony on page 9 at line

6 13, you quote the Commission Order that describes the PCA

7 that it ultimately adopted, and on line 13 on that page,

8 you quote the Commission stated that a procedure was

9 included in the PCA to guard against rate shock. Do you

10 see that?

11 A I do.

12 Q What was that procedure specifically?

13 A That was the procedure that I was speaking

14 about with Ms. Nordstrom that was the ability of the

15 Commission to look at potential increases greater than 7

16 percent to see whether or not circumstances warranted going

17 beyond the 7 percent.

18 Q Do you recall if that procedure had imposed

19 any responsibility on Idaho Power to proactively do

20 anything?

21 A I guess I'm not sure what you're referring

22 to.

23 Q Would you refer to your Exhibit No. 3, page

24 14? For the record, this is Commission Order 24806 which

25 is the Order quoted in Mr. Said's testimony. In the second

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1 full paragraph on that page, about two-thirds of the way

2 down there's a sentence that provides that "Idaho Power is

3 instructed to make a filing with the Commission...," do you

4 see that?

5 A Yes.

6 Q Did Idaho Power make a separate filing with

7 the Commission to address the rate shock issue?

8 A Let me read the entire sentence before I

9 respond. I guess the facts of this year are that we did

10 file early. We filed an emergency energy charge which is

11 essentially asking the Commission to make a determination

12 as to whether or not the costs should be recovered this

13 year or through another means.

14 Q And did you in that filing make a

15 recommendation that the costs be deferred?

16 A No.

17 Q And I think you mentioned to

18 Ms. Nordstrom the percentage increase that you were allowed

19 in this PCA, what was that percentage overall?

20 A My recollection of what she said was

21 30 percent.

22 Q And what is your definition of rate shock?

23 A I guess the way that rate shock has been used

24 in the past in proceedings before the Commission relate to

25 large changes in rates that potentially would be difficult

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1 on consumers.

2 Q Do you have a number in mind? What do you

3 mean when you say "large"?

4 A I don't know that that's ever been defined.

5 Q Is 7 percent large?

6 A The Commission has noted 7 percent as a point

7 at which it would make a determination as to whether or not

8 an amount in excess of that might be considered too large.

9 In the most recent proceeding, I guess I would say that

10 they decided 7 percent was not large.

11 Q Combined with the over 30 percent increase

12 that the Company has already received, if you're successful

13 in this proceeding and recover all the money you're asking

14 for, what would the overall percentage increase be?

15 A If I recall our original filing for the

16 entire amount, the overall rate increase was in excess of

17 40 percent.

18 Q And would you agree that deferral is an

19 appropriate and well used ratemaking mechanism to

20 ameliorate rate shock?

21 A I think it has been used. In the power cost

22 adjustment there is some deferral. There's at least a

23 year's deferral with regards to the true-up. In the

24 current case, deferral poses some financial problems that

25 Mr. Gribble discusses.

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1 Q So it is an appropriate method to ameliorate

2 rate shock or not?

3 A At times it is, yes.

4 MR. RICHARDSON: That's all I have,

5 Mr. Chairman. Thank you.

6 COMMISSIONER KJELLANDER: Thank you,

7 Mr. Richardson.

8 Are there questions from the Commission?

9 Commissioner Hansen.

10

11 EXAMINATION

12

13 BY COMMISSIONER HANSEN:

14 Q Mr. Said, I've just got a question on your

15 testimony on page 5, lines 17 through 21. Do you have

16 that?

17 A Yes.

18 Q I guess on lines 19 and 20 you talk about

19 matching the revenues to the actual power supply expenses

20 incurred by the Company and I guess I'd just like to ask

21 you a question, do you think the pricing mechanism of IES

22 matches the true cost to Idaho Power Company?

23 A The pricing of -- well, first let me state

24 that the transactions in this case that are being discussed

25 are the identification of those transactions which would

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1 have been operating or non-operating, because during the

2 period that this case covers IE didn't exist, so the

3 question is whether or not purchases made on behalf of the

4 utility were made at market prices and I do believe that

5 the pricing that has been established and used throughout

6 the PCA history have been prices that were reflective of

7 market price.

8 Q But in this case do you feel like as you sit

9 here in your testimony that they should closely match up?

10 I guess from the testimony that has been given, there's a

11 question that it doesn't. Do you agree that it doesn't?

12 A No, I don't. The statement being made about

13 matching expenses and revenues is basically a timing of

14 recovery of those expenditures and your question is a

15 little bit different, but at the same time, the way I'm

16 understanding your question is are the prices that have

17 been demonstrated or shown in our purchased power account

18 and our surplus sales revenues are those market prices and

19 I believe the answer is yes, so from that standpoint, if

20 you're calling that matching, the market prices are the

21 basis of the purchased power costs and the surplus sales

22 revenues that have been reported in the power cost

23 adjustment.

24 Q So are you saying that it's wrong to try to

25 match it up to exactly the cost of the purchase,

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1 transferring exactly what the cost of that power costs, the

2 affiliate, and matching that up to exactly what the

3 regulated Company is paying for it, you're saying you

4 really shouldn't be trying to match that?

5 A Well, I think what I'm saying is that the

6 utility's costs that are reported are the costs that the

7 utility incurred. The costs incurred by the non-operating

8 side of the business are not the costs of -- are not the

9 same as the cost of making purchases on behalf of the

10 utility, so I guess I would say that it's wrong to use the

11 costs of power used for non-operating purposes as a basis

12 for the costs of the utility.

13 COMMISSIONER HANSEN: Thank you. That's all

14 I have.

15 COMMISSIONER KJELLANDER:

16 Commissioner Smith.

17

18 EXAMINATION

19

20 BY COMMISSIONER SMITH:

21 Q Mr. Said, in your response to Commissioner

22 Hansen just now, something got by me I'm trying to capture

23 back. It was the answer to one of the first questions

24 based on the timing and you said something wasn't there

25 then. Could you explain what you're trying to say that I

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CSB REPORTING SAID (Com)
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1 didn't get?

2 A I'm not sure that I'm understanding.

3 Q Maybe our court reporter could read back the

4 response, I think it was, to his first question.

5 (A previous answer was read back by the

6 Notary Public.)

7 Q BY COMMISSIONER SMITH: So IE --

8 A Idaho Energy.

9 Q -- didn't exist?

10 A Did not exist.

11 Q That's the part I missed. Mr. Said, you were

12 here at the beginning of the PCA?

13 A I was.

14 Q And you've been here through most of the

15 years that it's operated?

16 A Yes.

17 Q When the PCA was first implemented, what's

18 your sense of the magnitude of cost changes that were

19 anticipated?

20 A My recollection is that system power supply

21 costs had a variation from worst case to best case of about

22 $120 million.

23 Q In the beginning?

24 A Yes.

25 Q Okay. Based on what's happened in the, I

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1 guess I'll call it, 2000-2001 PCA year, do you think we

2 need to make any changes, we need to look at this again?

3 A Well, it's very apparent that the magnitude

4 of those swings is far greater than it was at the time that

5 the power cost adjustment was established. I think

6 additional review of the power cost adjustment should go on

7 on an ongoing basis to see whether or not it's performing

8 as intended. I guess my conclusion is that in the past

9 year when the expenses rose so high that the power cost

10 adjustment was probably a Godsend to the Company in that it

11 did have a means of dealing with extreme expense

12 situations.

13 There are some rate shock issues associated

14 with the magnitude of expenses that can be seen today, and

15 as has been addressed in this case, there are some issues

16 about resource planning that may also need some review in

17 terms of whether the Company plans its resources on a

18 median streamflow or something less than a median

19 streamflow. Circumstances in the utility business have

20 certainly changed and I think that we would be remiss not

21 to look at those circumstances and see if there are

22 adjustments that need to be made in a number of areas

23 within the utility.

24 Q Well, I'll just state my concern because I

25 think I was here at the beginning, too, and what I recall

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1 is everyone was thinking mainly about fluctuations in hydro

2 conditions.

3 A Right.

4 Q And good water years giving the customer some

5 benefit of that, giving the Company some financial security

6 in a kind of a streamline way in bad water years. I don't

7 know that anyone -- personally, I don't think this is a bad

8 water year, this is a catastrophic event, it's the worst.

9 It's not just bad, it's like the catastrophic event, so I

10 don't think anyone even had this bad of water in mind, but

11 I don't think anyone intended or imagined that we would

12 find ourselves in the position of recovering tens of

13 millions of dollars because of some spike in a market

14 price, and my concern is that the incentives of a PCA for a

15 utility are to just buy it and pass it through and the PCA

16 doesn't really, isn't built for a company to look at a

17 market that's gone crazy and develop a new strategy for

18 procuring supply in the face of that, so I guess my

19 question was, how do we begin to look at creating a process

20 that does give the correct incentives in that kind of

21 situation? And if you want to think about it, I'm sure

22 that that's not going to decide the dollars in this case,

23 so you can get back to me on that later.

24 A Okay.

25 COMMISSIONER SMITH: Thank you,

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1 Mr. Chairman.

2

3 EXAMINATION

4

5 BY COMMISSIONER KJELLANDER:

6 Q I think that was an easy out in response to a

7 difficult question and I've got one follow-up, I think, in

8 part to a question asked by Mr. Richardson and perhaps I'm

9 mischaracterizing the question, but it did bring to mind

10 the issue of proactive positions that could be taken by a

11 company to avoid rate shock. I think in the context of his

12 question, it sort of came down to, if I'm correct, in

13 answer about a filing to the Commission. Is that the only

14 action that the Company should have been looking at or

15 should be looking at today as it relates to trying to avoid

16 rate shock? What proactively should a company be doing to

17 avoid that circumstance from occurring?

18 A I think that you're absolutely right, that

19 the filing isn't the only avenue that the Company should be

20 pursuing to try and prevent rate shock. What the Company

21 does through management and to a part with the Risk

22 Management Committee is look at the forward positions of

23 the Company and the utility in terms of whether or not it

24 anticipates having deficiencies in the future, and

25 historically, what the Company has done is try and evaluate

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1 the best opportunities to procure power in times of when

2 deficiencies occur and I think that essentially that's

3 probably the major thing that the Company can be doing on

4 an ongoing basis to try and eliminate or reduce rate shock

5 is manage their resources as best they can to minimize

6 costs.

7 This kind of touches on what

8 Commissioner Smith had talked about about the incentives

9 that the Company has to do that. With the existing

10 mechanism, there's a 90 percent-10 percent sharing of the

11 deviation in costs and if I understand the Commissioner's

12 statement, perhaps that 10 percent isn't or wouldn't be

13 viewed as an adequate incentive for the Company to keep

14 costs down.

15 I think from my understanding of seeing the

16 Risk Management Committee decisions, they take all of the

17 circumstances into consideration to a large extent and do

18 the best that they can to keep costs as low as they can.

19 Circumstances this year have certainly gotten the better of

20 us, but learning from experiences hopefully will help in

21 the future in terms of keeping costs as low as possible, so

22 I think that's the primary area where the Company can seek

23 to keep costs down and, therefore, recovery requests

24 through the PCA in manageable areas. Hopefully, market

25 conditions and prices won't continue to see spikes like

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1 we've seen in the last year.

2 Q Just as a follow-up, then, with the market

3 spikes that we have seen in the last year, what's a good

4 way to avoid those spikes?

5 A The easiest way to avoid the cost of

6 potential market spikes is to have sufficient resources to

7 meet your loads under any condition. The problem with that

8 is that there's a cost of having power supply available

9 during all time periods, even when you have abundant

10 resources, when market prices may be extremely low and so

11 you're paying for idle resources, so there's kind of a

12 balancing there between a willingness to accept short-term,

13 high-cost spikes as opposed to having ongoing higher base

14 levels of load or of rates to cover a higher level of

15 resources available so that you don't have to rely on the

16 market.

17 Q But knowing that you don't have those

18 resources and you have to rely on the market, what's the

19 best way to avoid those spikes?

20 A That comes down to an issue of being able to

21 potentially time the market which is a difficult thing. We

22 certainly try and employ the people with the most expertise

23 and knowledge of what markets may do so that they can

24 perhaps anticipate some of those spikes. In last year

25 where those price spikes had never occurred, it was

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1 somewhat difficult to envision. Perhaps with some

2 experience of price spikes now there may be the procuring

3 of power further in advance of potential market spikes.

4 Again, there's a risk associated with doing

5 that in that you're potentially locking into a price today,

6 although you can also go out and procure power that would

7 be tied to a future price. That doesn't avoid the market

8 price spike, though, if you do it that way, so in the

9 alternative of going out and buying resources, you could go

10 out and make purchases, long-term purchases, in advance, in

11 essence locking up resources, to avoid future dependence on

12 a market with an unknown price.

13 COMMISSIONER KJELLANDER: Thank you,

14 Mr. Said. I appreciate your testimony and that's all the

15 questions that I have.

16 I think we're ready, then, for redirect from

17 Mr. Ripley.

18 MR. RIPLEY: Thank you.

19

20 REDIRECT EXAMINATION

21

22 BY MR. RIPLEY:

23 Q Mr. Said, just so that I'm clear, the

24 transmission and wheeling revenues and expenses were never

25 included in the PCA?

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1 A That's correct.

2 Q And they are currently excluded from the PCA

3 computations?

4 A That's correct.

5 Q If I understand your testimony correctly,

6 when asked have circumstances changed, I assume that that

7 would mean that the Commission and the parties and Idaho

8 Power Company could look on a prospective basis as to

9 whether there should be changes in the exclusion or

10 inclusion of certain accounts in the PCA?

11 A That would certainly be my expectation that

12 any change in the accounts included in PCA determinations

13 would be prospective.

14 Q You were asked whether or not rates that were

15 reasonable could become unjust and unreasonable and if

16 there's any corrections, would that be done on a

17 retroactive or on a prospective basis?

18 A A prospective basis.

19 Q Now, in response to some of the questions

20 from the Commissioners as to what the Company could or

21 could not do, those are issues, I assume, you were speaking

22 of in a prospective sense?

23 A In terms of satisfying future deficiencies or

24 avoiding market spikes?

25 Q Yes.

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1 A Yes, I don't think there's a way to avoid the

2 market spikes of the past, we've already experienced

3 those.

4 MR. RIPLEY: That's all the questions I

5 have.

6 COMMISSIONER KJELLANDER: Thank you,

7 Mr. Ripley. I think that this might be appropriate time to

8 take a break, so why don't we take one for roughly ten

9 minutes and come back and we can excuse your witness and

10 we'll do so before we go off the record. Thank you,

11 Mr. Said, for your testimony.

12 THE WITNESS: Thank you.

13 (The witness left the stand.)

14 (Recess.)

15 COMMISSIONER KJELLANDER: All right, we'll go

16 back on the record and I believe that we're ready for your

17 next witness, Mr. Ripley.

18 MR. RIPLEY: Thank you. We call

19 Mr. Gribble.

20

21

22

23

24

25

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Wilder, Idaho 83676 Idaho Power Company

1 DENNIS C. GRIBBLE,

2 produced as a witness at the instance of the Idaho Power

3 Company, having been first duly sworn, was examined and

4 testified as follows:

5

6 DIRECT EXAMINATION

7

8 BY MR. RIPLEY:

9 Q Would you state your name for the record,

10 please?

11 A It's Dennis C. Gribble.

12 Q And your business address?

13 A 1221 West Idaho.

14 Q Mr. Gribble, did you have cause to be

15 prepared for this proceeding certain prefiled testimony

16 consisting of eight pages?

17 A Yes, I did.

18 Q And you have no exhibits?

19 A Correct.

20 Q If I asked you the questions that are set

21 forth in that testimony, would your answers be the same

22 today?

23 A Yes, they would.

24 MR. RIPLEY: We would ask that

25 Mr. Gribble's testimony be spread upon the record as if

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Wilder, Idaho 83676 Idaho Power Company

1 read and would tender him for cross-examination.

2 COMMISSIONER KJELLANDER: Without objection,

3 then, Mr. Gribble's testimony will be spread across the

4 record.

5 (The following prefiled testimony of

6 Mr. Dennis Gribble is spread upon the record.)

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

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CSB REPORTING GRIBBLE (Di)
Wilder, Idaho 83676 Idaho Power Company

1 Q. Please state your name, business address and

2 present occupation.

3 A. My name is Dennis C. Gribble and my business

4 address is 1221 West Idaho Street, Boise, Idaho. I am

5 employed by Idaho Power Company as Assistant Treasurer.

6 Q. What is your educational background?

7 A. I graduated in 1975 from Boise State

8 University, Boise, Idaho, receiving a Bachelor of Business

9 Administration degree in Economics. In 1978, I graduated

10 from Boise State University, Boise, Idaho, with a Master in

11 Business Administration. In 1989, I completed the

12 University of Idaho's Public Utilities Executive Course in

13 Moscow, Idaho. I have also attended numerous seminars and

14 conferences on accounting and finance issues related to the

15 utility industry. I am a Certified Cash Manager.

16 Q. Would you please describe your business

17 experience with Idaho Power Company?

18 A. In 1979, I was employed by Idaho Power Company

19 and assigned to the Systems Development Department as an

20 Associate Systems Analyst. In June 1982, I transferred to

21 the Finance and Reporting Services Department as a Business

22 Analyst. In June 1986, I was promoted to a Business Analyst

23 Supervisor. In March 1991, I was promoted to Manager of

24 Financial Services. In January 1992, I was promoted to

25 Manager of Corporate Accounting and Reporting. In 1996, I

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Idaho Power Company

1 was promoted to Controller-Financial Services and in May

2 1999 I was promoted to my current position as Assistant

3 Treasurer.

4 Q. What are your duties as Assistant Treasurer?

5 A. The Assistant Treasurer assists in setting

6 the treasury department strategic goals, objectives, and

7 budgets. Among my duties I oversee the direct financial

8 planning, procurement, investment of funds for Idaho Power,

9 and supervision of corporate liquidity management.

10 Q. What is the purpose of your testimony?

11 A. I will be addressing the cash flow

12 implications to the Company of deferring costs incurred in

13 one period for recovery in future periods. Also, my

14 testimony will discuss the financial implications resulting

15 from a regulatory authority denying recovery of all or a

16 portion of costs, which the Company believed had previously

17 been approved by the same regulatory authority for deferral

18 and recovery in a future period.

19 Q. What is the effect of denying all or a

20 portion of costs deferred for recovery in a future period?

21 A. Current expenditures granted deferral for

22 future recovery under accounting guidelines must be

23 immediately recognized as an expense in the period that

24 recovery is denied. Such an event could have a significant

25 negative financial impact on the net income and cash

106

GRIBBLE, DI 2
Idaho Power Company

1 liquidity of the Company.

2 Q. How has the Company financed the purchase of

3 wholesale power acquired to serve its Idaho retail load for

4 the period May 15, 2000 through February 28, 2001?

5 A. The Company has financed the purchase of

6 wholesale power for its Idaho retail load during this

7 period by utilizing its short-term borrowing capacity via

8 the issuance of commercial paper.

9 Q. How does the Company record the financial

10 transaction of issuing commercial paper used to pay for

11 this wholesale power?

12 A. The cash proceeds received from these short-

13 term loans are used to pay for the wholesale purchased power

14 costs. These short-term loans are recorded as a liability

15 on the Company's balance sheet, indicating a claim on the

16 Company by the creditors investing in its commercial paper.

17 Q. How did the Company plan to pay for these

18 short-terms loans?

19 A. The Company planned to pay these short-term

20 loans primarily from increased revenue as a result of the

21 Power Cost Adjustment (PCA) in its Idaho jurisdiction.

22 Q. Does the Company record the purchase of

23 wholesale purchased power under Generally Accepted

24 Accounting Principles (GAAP)?

25 A. Yes. However, it is important to distinguish

107

GRIBBLE, DI 3
Idaho Power Company

1 between the recording of these transactions under GAAP, the

2 cash payments for wholesale purchased power, and the

3 subsequent recovery of that cash. When the Company incurs

4 wholesale purchased power costs to supply power to its

5 Idaho retail customers, these transactions are classified

6 as expenses (subtractions) in the financial reporting of

7 net income, unless as I will discuss later, there is a

8 regulatory order modifying this process. Typically the

9 Company would have a cash inflow (revenues) available to

10 offset these wholesale purchased power costs (expenses) in

11 the period the purchase occurs. Regardless of the

12 Company's sources and timing of cash inflows, GAAP requires

13 the Company to record an expense for the cost of wholesale

14 power purchased in the period it occurs. Only if granted a

15 special accounting order from the participating regulatory

16 agency, will the Company be allowed to defer expenses for

17 recovery in a future period. As an example, under GAAP the

18 Company is required to immediately recognize the purchase

19 of wholesale power as an expense, even though the cash

20 inflows to the Company may not offset these expenses in the

21 period the expense was incurred. Since this mismatch of

22 expense recognition and cash flow typically places negative

23 financial pressure on regulated utilities, regulatory

24 authorities can issue an accounting order that allows the

25 Company under GAAP to defer expense recognition from the

108

GRIBBLE, DI 4
Idaho Power Company

1 period in which the expense was incurred for recovery in a

2 future period. The accounting order issued by the

3 regulatory authority must also provide an assurance of

4 funding of the deferred expense. The Company's current PCA

5 in its Idaho jurisdiction is an example of such an

6 accounting order that allows the Company treatment of power

7 supply expenses differently than other entities not subject

8 to regulation.

9 Q. Has the current PCA helped minimize the

10 timing differences for the period (May 15, 2000 through

11 February 28, 2001) you have referenced above?

12 A. Yes. Again, the PCA is based upon an

13 accounting order granted by the Idaho Public Utilities

14 Commission (IPUC) authorizing the Company to defer 90% of

15 the Idaho retail jurisdictions extraordinary wholesale

16 purchased power costs. The 90% of the Idaho jurisdiction

17 is equivalent to approximately 75% of the total system

18 extraordinary wholesale purchased power costs. This

19 deferral authorizes the Company under GAAP to defer these

20 expenses in essentially a holding account for future

21 recovery. Each year, the Company then files the PCA with

22 the IPUC for recovery of these deferred expenses. When the

23 IPUC grants recovery, Idaho retail rates are then adjusted

24 to recover the necessary cash expended for the deferred

25 wholesale purchase power expenditures.

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GRIBBLE, DI 5
Idaho Power Company

1 Q. What would be the financial implications to

2 the Company if it did not have the PCA?

3 A. Unless the Company is granted a special

4 accounting order such as the PCA, the Company could incur

5 negative financial results and cash liquidity pressure due

6 to the mismatch of immediate expense recognition (such as

7 wholesale purchased power costs), and the cash inflow

8 (revenues) necessary to support those expenditures.

9 Q. Has there been any discussions with the

10 Company's outside auditor or the Financial Accounting

11 Standards Board (FASB) regarding the ability of regulated

12 utilities to defer expenditures incurred in a current

13 period to a future period?

14 A. Yes. Deferral accounting for regulated

15 utilities falls primarily under the Statement of Financial

16 Accounting Standards No. 71 (SFAS 71). SFAS 71 states, "For

17 a number of reasons, revenues intended to cover some costs

18 are provided either before or after the costs are incurred.

19 If regulation provides assurance that incurred costs will

20 be recovered in the future, this Statement requires companies

21 to capitalize those costs. If current recovery is provided

22 for costs that are expected to be incurred in the future,

23 this Statement requires companies to recognize those current

24 receipts as liabilities". SFAS 71 also indicates that,

25 "Rate actions of a regulator can reduce or eliminate the

110

GRIBBLE, DI 6
Idaho Power Company

1 value of an asset. If a regulator excludes all or a part

2 of a cost from allowable costs and it is not probable that

3 the cost will be included as an allowable cost in a future

4 period, the cost cannot be expected to result in future

5 revenue through the rate-making process. Accordingly, the

6 carrying amount of any related asset shall be reduced to

7 the extent that the asset has been impaired". As SFAS 71

8 demonstrates, the major concern for the Company's outside

9 auditor and in general the accounting profession, is in

10 validating the recoverability of costs that have been

11 authorized for recovery in a later period (deferred). To

12 the extent a regulator's authorization for deferral is

13 denied, GAAP would require the immediate expense recognition

14 of those costs for financial reporting purposes.

15 Q. What would be the financial effect to the

16 Company if costs it believed had been deferred by a

17 regulatory authority for recovery in a future period were

18 then subsequently denied by the same regulatory authority?

19 A. Under GAAP, those costs deferred for future

20 recovery would be immediately recognized as an expense in

21 the period that recovery was denied by the regulator. Such

22 an event would place a significant downward impact on the

23 net income of the Company for financial reporting purposes.

24 Likewise, the Company would not have recovered the necessary

25 cash to offset the expenses incurred, and would face

111

GRIBBLE, DI 7
Idaho Power Company

1 negative financial pressure on its cash liquidity.

2 Q. Please describe the accounting entries if the

3 Company is not permitted to recover the $59 million of

4 deferred power supply costs.

5 A. The $59 million of deferred power supply

6 costs are currently recorded on the Company's books in

7 Account 182.3 - Regulatory Assets. If not permitted

8 recovery of these deferred expenses, the Company would be

9 required under GAAP to credit $59 million to Account 182.3 -

10 Regulatory Assets (to eliminate the deferral status) and

11 debit $59 million to Account 557 Other Power Production

12 Expense (to record the expense). The resultant financial

13 impact is a reduction of $59 million, shown as an expense

14 to the Company's income statement, in the financial

15 reporting period that corresponds with the denial to

16 recover the $59 million of deferred power supply costs.

17 Q. Does this conclude your testimony?

18 A. Yes.

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GRIBBLE, DI 8
Idaho Power Company

1 (The following proceedings were had in

2 open hearing.)

3 COMMISSIONER KJELLANDER: And we're ready now

4 for the Attorney General's attorney representing Staff.

5 MS. NORDSTROM: Thank you.

6

7 CROSS-EXAMINATION

8

9 BY MS. NORDSTROM:

10 Q Good morning.

11 A Good morning.

12 Q On page 2, beginning on line 21, you state

13 that expenditures granted deferral must be immediately

14 expensed in the period that recovery is denied; is that

15 correct?

16 A That's correct.

17 Q If recovery is denied for the contested

18 amounts, when would the expense be recorded?

19 A They would actually be recorded in the period

20 that the denial is issued by a commission or regulatory

21 authority. Typically, for financial reporting purposes, it

22 would be reflected in the quarter in which that was denied.

23 Q So that would be the quarter in which the

24 Commission order became final?

25 A That's correct.

113

CSB REPORTING GRIBBLE (X)
Wilder, Idaho 83676 Idaho Power Company

1 Q When the expenditures in this case were

2 deferred in the second through fourth quarter of 2000

3 and the first quarter of 2001, isn't it true that the

4 actual booked expenses were reduced as a result of the

5 deferral?

6 A Yes, that's true to the extent the PCA

7 mechanism allows 90 percent of those deferrals for the

8 Idaho jurisdiction, that's correct.

9 Q Didn't the deferral increase the net income

10 in the quarter the deferral was recorded?

11 A The deferral allows the Company not to

12 recognize the expense at that point in time.

13 Q But doesn't that increase the net income in

14 that quarter?

15 A That's correct.

16 Q Denial of recovery would then delay the

17 recording of the expenditure as an expense and the impact

18 on net income; correct?

19 A It would delay the impact at that point in

20 time; whereas, denial would have the impact reflected at

21 the point of the denial.

22 Q On page 3, lines 5 through 8, you state that

23 the Company financed the purchase of wholesale power by

24 utilizing short-term borrowing capacity. Absent a PCA, how

25 would the Company probably finance these expenditures?

114

CSB REPORTING GRIBBLE (X)
Wilder, Idaho 83676 Idaho Power Company

1 A Absent a PCA, the Company still would

2 probably use some type of short-term financing capacity to

3 do that. Again, there is a limit to the amount of the

4 impact financially on the Company when deferral is not

5 allowed, but the financing of the actual expenditures from

6 the cash expenditure, we would use some sort of short-term

7 borrowing facility to purchase that power.

8 Q Isn't it true that under normal ratemaking

9 extraordinary power costs would not be reflected in current

10 rates?

11 A Under normal ratemaking the basic

12 expenditures for the utility would take into account

13 some expenditure for purchased power costs and to the

14 extent those aren't adequately recovered in a particular

15 period, then they would be outside the normal ratemaking

16 process.

17 Q On page 4, lines 8 through 11, you state:

18 "Typically the Company would have a cash inflow (reserves)

19 available to offset these wholesale purchased power

20 costs (expenses) in the period the purchase occurs."

21 Isn't it true that for the period corresponding to the

22 2000-2001 PCA year this statement would not be accurate

23 since market prices were extraordinary and higher than the

24 prior year's actual costs for normalized purchased power

25 costs?

115

CSB REPORTING GRIBBLE (X)
Wilder, Idaho 83676 Idaho Power Company

1 A Yes, that's correct.

2 Q Referring to page 5, lines 2 through 4, isn't

3 it true that the assurance of funding the deferred

4 expenses is not an absolute guarantee for funding, rather

5 that the funding will reflect prudent and reasonable

6 expenditures?

7 A The issue with the accounting order and the

8 basis for deferral, the prudency of those costs are always

9 questions that can be looked at at the point in time,

10 especially in this case, the PCA hearings. What is

11 at issue here is when you're allowed to defer costs,

12 the processes and the procedures and the way that

13 those costs are incurred, those are what provide the

14 basis for the accountants or the accounting community

15 to allow a deferral to go forward. Prudency is always

16 an issue in terms of what is the actual allowed cost

17 that would be looked at during a PCA hearing, but the

18 process and the procedures and the methodology in which

19 you actually incurred those costs, those are what are

20 reviewed to allow for a deferral process.

21 MS. NORDSTROM: Thank you. No further

22 questions at this time.

23 COMMISSIONER KJELLANDER: We'll move now to

24 Mr. Richardson.

25 MR. RICHARDSON: No questions, Mr. Chairman.

116

CSB REPORTING GRIBBLE (X)
Wilder, Idaho 83676 Idaho Power Company

1 COMMISSIONER KJELLANDER: Are there questions

2 from the Commission?

3 None from the Commission, we're ready for

4 redirect.

5

6 REDIRECT EXAMINATION

7

8 BY MR. RIPLEY:

9 Q Mr. Gribble, just to follow up on that

10 last question you were asked, if the procedures could

11 be changed dramatically, would the Company be able to

12 defer costs under normally recognized accounting

13 procedures?

14 A If they were changed drastically, no, they

15 would not be allowed to, because at that point in time the

16 basis for the deferral would have changed, so they would

17 not be allowed to.

18 MR. RIPLEY: Thank you. That's all the

19 questions I have.

20 COMMISSIONER KJELLANDER: Mr. Gribble, we

21 appreciate your testimony and we'll excuse you at this

22 time. Thank you.

23 MR. RIPLEY: Might I ask if Mr. Gribble could

24 be excused from the hearings to attend other duties?

25 COMMISSIONER KJELLANDER: And without

117

CSB REPORTING GRIBBLE (Di)
Wilder, Idaho 83676 Idaho Power Company

1 objection?

2 MS. NORDSTROM: Staff has no objection.

3 COMMISSIONER KJELLANDER: Without objection,

4 then, Mr. Gribble will be excused.

5 MR. RIPLEY: Let me say as a postscript that

6 if some question comes up, Mr. Gribble is in town. I've

7 instructed him not to go on vacation.

8 COMMISSIONER KJELLANDER: Fair enough. Thank

9 you.

10 THE WITNESS: Thank you.

11 (The witness left the stand.)

12 COMMISSIONER KJELLANDER: Mr. Ripley, we're

13 ready for your next witness.

14 MR. RIPLEY: We call Mr. Anderson.

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118

CSB REPORTING GRIBBLE (Di)
Wilder, Idaho 83676 Idaho Power Company

1 DARREL T. ANDERSON,

2 produced as a witness at the instance of the Idaho Power

3 Company, having been first duly sworn, was examined and

4 testified as follows:

5

6 DIRECT EXAMINATION

7

8 BY MR. RIPLEY:

9 Q Would you state your full name for the

10 record, please?

11 A Darrel T. Anderson.

12 Q And your business address?

13 A 1221 West Idaho Street.

14 Q And, Mr. Anderson, did you have cause to be

15 prepared for this proceeding certain prefiled testimony

16 consisting of 11 pages?

17 A Yes, I did.

18 Q And if I asked you the questions that are set

19 forth in that testimony, prefiled testimony, would your

20 answers be the same today?

21 A Yes, they would.

22 Q And you have no exhibits?

23 A That's correct.

24 MR. RIPLEY: We would request that

25 Mr. Anderson's testimony be spread upon the record as if

119

CSB REPORTING ANDERSON (Di)
Wilder, Idaho 83676 Idaho Power Company

1 read and would tender him for cross-examination.

2 COMMISSIONER KJELLANDER: And without

3 objection, then, Mr. Anderson's testimony will be spread

4 across the record.

5 (The following prefiled testimony of

6 Mr. Darrel Anderson is spread upon the record.)

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120

CSB REPORTING ANDERSON (Di)
Wilder, Idaho 83676 Idaho Power Company

1 Q. Please state your name, business address and

2 present occupation.

3 A. My name is Darrel T. Anderson and my business

4 address is 1221 West Idaho Street, Boise, Idaho. I am Vice

5 President of Finance and Treasurer of Idaho Power Company.

6 I am also Vice President of Finance and Treasurer for

7 IDACORP.

8 Q. What is your educational background?

9 A. I graduated from Oregon State University with

10 a Bachelor of Science Degree in Accounting and Finance in

11 1979. I am a licensed CPA in the state of Oregon (#4312

12 inactive). Before joining Idaho Power Company in 1996, I

13 was the Chief Financial Officer of Sisters of Saint Mary of

14 Oregon. Prior to joining the Sisters of Saint Mary of

15 Oregon I was a senior manager of Audit Services for

16 Deloitte & Touche and was a firm-designated specialist in

17 electric and gas utility operations. I left Deloitte &

18 Touche in 1995.

19 Q. When did you come to Idaho Power and what

20 positions have you held at Idaho Power?

21 A. I joined Idaho Power in 1996 as a Controller

22 in the Finance Department. In 1998, I moved to Lacey, WA,

23 where I served as Executive Vice President of Finance and

24 Operations at Applied Power Corporation, a subsidiary of

25 IDACORP. In April 1999 I became Idaho Power Company's Vice

121

ANDERSON, DI 1
Idaho Power Company

1 President of Finance and Treasurer. In this capacity I am

2 responsible for all aspects of financial and treasury

3 management.

4 Q. Are you a member of the Risk Management

5 Committee (RMC)?

6 A. Yes, I am the chairperson of the RMC. In

7 this capacity I am responsible for conducting the meetings,

8 managing the agenda and recording the minutes of the

9 meetings.

10 Q. When was RMC formed?

11 A. The RMC was originally formed in 1996 in

12 response to the Company's decision to enter into the

13 non-regulated speculative commodity trading business.

14 Q. What is the purpose of the RMC?

15 A. The purpose of the RMC is to maintain general

16 oversight over all commodity trading and financial risk

17 management operations. The committee consists of officers

18 of Idaho Power Company and IDACORP. The committee meets as

19 required to review exposure reports, profit and loss

20 reports, credit and trading limits, and trading strategies

21 and objectives. As noted previously, the origination of

22 the committee was a direct result of the Company's decision

23 to participate in the non-regulated speculative commodity

24 energy trading business. Prior to the formation of the

25 committee, there was no formal oversight group of the power

122

ANDERSON, DI 2
Idaho Power Company

1 supply activities of Idaho Power Company other than that of

2 the management personnel responsible for the unit's

3 activities. Over a period of time it became evident that

4 some of the same risks and issues that were associated with

5 the non-regulated speculative trading activities were also

6 evident on the regulated side of the business. In 1999 the

7 RMC began to expand its role to look at issues surrounding

8 the supply and demand side of the Company's regulated

9 business. During the period between 1999 and June 2001,

10 the business practices related to the review of the

11 regulated operations evolved. Process improvements have

12 been focused on the gathering and summarizing of relevant

13 data that impacts the operating system, including supply

14 and demand requirements, market price data, risk mitigating

15 products, and potential hedging strategies.

16 Q. Please discuss the procedures that the RMC

17 follows when reviewing the energy requirements for Idaho

18 Power Company system operations.

19 A. The RMC reviews operating proposals prepared

20 by Idaho Power Company personnel. The proposals include

21 assumptions for supply and demand requirements based on

22 data available at that time. Based on the results of this

23 data, the collective experience of the committee members,

24 other pertinent internal and external data, and an in-depth

25 discussion between committee members, decisions are made to

123

ANDERSON, DI 3
Idaho Power Company

1 determine the need to buy or sell energy. Numerous factors

2 are considered in coming to these decisions including

3 weather, expected load requirements, current snowpack,

4 transmission availability, pricing and the overall system

5 portfolio position. When it is determined that an action

6 is required, a recommendation is made by a committee member

7 and put to the entire RMC for a vote. A majority is

8 required to confirm a transaction. Once a decision has

9 been reached, the traders that would consummate the

10 transactions are notified either by written hard copy memo

11 or by e-mail. Historically, the notification includes the

12 following: (a) the volume, (b) the time period of the

13 transaction and, (c) other relevant instructions such as

14 price ranges, and/or time periods to complete the purchase.

15 Q. Explain the circumstances surrounding what

16 the Commission in Order No. 28722 characterizes as the

17 "November transaction."

18 A. The "November transaction" refers to an entry

19 in the minute records that indicates the approval of a

20 purchase transaction in the amount of 75 MW for the month

21 of January 2001 at a price that is subject to the judgment

22 of the head trader.

23 Q. Describe the events surrounding the "November

24 transaction."

25 A. The RMC, at its meeting on November 21, 2000,

124

ANDERSON, DI 4
Idaho Power Company

1 reviewed a proposal that indicated a net long position of

2 1,300 MW through the balance of the 2000-2001 Power Cost

3 Adjustment (PCA) year. The proposal indicated a net short

4 position during this period of 80 MW and 63 MW for the

5 months of December 2000 and January 2001 respectively. The

6 RMC reviewed various factors affecting the Company's

7 position in its portfolio and initially concluded that a

8 hedge of up to 75 MW for January 2001 should be considered,

9 with price subject to the discretion of the head trader.

10 In further discussions at the same meeting, a number of

11 additional factors were discussed that are noted below:

12 (a) The proposal presented at the meeting

13 indicated a surplus position during the balance of the

14 year, which when considered on a portfolio basis for the

15 system, indicated adequate length overall for the system.

16 (b) The pricing for January 2001 was in the

17 $150-$170 per MWh range at the time of the meeting which

18 when compared to historical amounts for January 1999 and

19 January 2000, (ranged between approximately $15 and $25 for

20 the respective periods) was 6-10 times recent historical

21 prices.

22 (c) The initial snowpack reports for the

23 2001 water year indicated snowpack conditions that were on

24 track with or slightly below normal conditions. The

25 November snowpack numbers are very early returns and are not

125

ANDERSON, DI 5
Idaho Power Company

1 necessarily conclusive as to the type of water flow that

2 can be achieved in the forward months.

3 Q. What effect did these factors have on the RMC

4 deliberations?

5 A. These factors combined to make the committee

6 reconsider its decision in the same meeting and conclude

7 that the original transaction should not be considered at

8 this time based on the factors I have just discussed.

9 Q. Did prices rise significantly after the

10 November meeting indicating the "November transaction"

11 should have been consummated.

12 A. Given the benefit of hindsight and therefore

13 knowing about the anticipated December cold spell, the

14 "Siberian Express", and the "California energy crisis,"

15 along with the resultant run up in prices in the region,

16 the Company may have reconsidered its decision to hedge the

17 deficits in January 2001. I say possibly, because being

18 short in a given period may not be detrimental to the

19 overall results, because a run-up in prices when a company

20 is in an overall long position could be of a larger benefit

21 to the organization than covering a short position for a

22 particular month. For example, if the Company elects to

23 cover a specific short position, it in effect increases the

24 entities overall long position and will correspondingly

25 increase the Company's overall risk to falling market price

126

ANDERSON, DI 6
Idaho Power Company

1 changes. Subsequent to the meeting on November 21, 2000,

2 the Company entered into another transaction that supports

3 the above philosophy when it sold some of the First Quarter

4 2001 length and purchased Third Quarter 2001, thereby

5 locking in a spread between these prices for the benefit of

6 the retail customers. This transaction was executed during

7 the week of November 30, 2000. Had the positions reflected

8 significant portfolio shortages for the First Quarter 2001,

9 this transaction would not have been completed.

10 Q. Given the above discussion, what is your

11 explanation of what happened in the documentation process

12 of the November 21, 2000 meeting?

13 A. As chairperson of the RMC, I was also

14 responsible for taking the minutes of the meetings. In

15 this capacity, I took hand notes and then later recorded

16 the minutes in typed form. In this instance, I recorded

17 the discussions of the request to hedge the position but

18 did not record the subsequent reversal of the decision. As

19 noted earlier, the RMC process has evolved over time and

20 the minute entries did not go through a formalized approval

21 process by the committee. Had this review process been in

22 place, the error in the minutes would have been noted and

23 corrected and we would not have an issue related to this

24 item.

25 Q. In addition to the discussions that took

127

ANDERSON, DI 7
Idaho Power Company

1 place at the RMC meeting is there any other indication that

2 this issue is nothing more than an error in the recording

3 of the RMC minutes?

4 A. Yes. In addition to the discussions that

5 took place at the RMC meeting there was a follow-up process

6 that allowed for a check and balance when a formal decision

7 was made. The traders would not execute a transaction

8 without some form of written authorization (either written

9 memo or e-mail) from myself or Rich Riazzi, Senior Vice

10 President of Marketing and Generation. The head trader

11 also followed up with me when a trade had been approved by

12 the RMC to ensure that the terms of the transaction were

13 what had been approved. Consistent with the ultimate

14 decision of the RMC, no transaction was executed for this

15 item by the traders.

16 Q. In your opinion is it reasonable to penalize

17 the Company $7,976,701 for an error in the recording of the

18 RMC minutes?

19 A. No.

20 Q. Please explain why the RMC did not engage in

21 more hedging of power supply costs in November and December

22 of 2000, and January and February of 2001.

23 A. I would first point out that prior to the

24 time period referred to, the Company had been proactive in

25 hedging system requirements to the benefit of the Idaho

128

ANDERSON, DI 8
Idaho Power Company

1 retail customer. I have previously described the

2 conditions that existed in November. Looking beyond

3 November, there were a number of issues that created a

4 period of uncertainty in the regional energy markets. The

5 "California energy crisis," the threat of a "Siberian

6 Express", a cold spell in December that did not

7 materialize, and a gradually declining water situation, all

8 put heavy pressure on regional energy prices.

9 Q. Did water conditions play a significant role

10 during this period?

11 A. Yes. With regard to the water situation,

12 Idaho Power Company is predominately a hydro-based utility

13 and therefore heavily reliant on precipitation and snowfall

14 in our region. The snowpack generally accumulates during

15 the water year period between November and March. In a

16 normal year we can expect up to 60 percent of our

17 generation to come from hydro resources. As we monitored

18 the snowpack accumulation during this period, the Company

19 closely analyzed its power supply position to determine the

20 need and cost to hedge potential shortfalls, since regional

21 prices were already very high. The RMC looked at the overall

22 power supply position to determine the needs of the Company

23 and it was not until mid-January and early February 2001

24 that it became evident that normal or near normal snowpack

25 accumulation was not likely to materialize in 2001.

129

ANDERSON, DI 9
Idaho Power Company

1 However, even then the full extent of the drought was not

2 known. Given the available information, the Company took

3 measures to begin mitigating the lack of precipitation in

4 our region. These measures eventually included both demand

5 and supply options as alternatives to market purchases.

6 Because of the planning (and sometimes approval) time

7 required to develop the mitigation measures, these measures

8 could not be implemented until after February 28, 2001.

9 The measures that were instituted are well documented. For

10 example, load reduction programs, energy purchases, the

11 institution of additional temporary generating resources,

12 and conservation advertising.

13 Q. In your opinion, were the power supply

14 activities of the Company reasonable and prudent for the

15 period November and December of 2000 and January and

16 February of 2001?

17 A. Yes. Because the Company is a predominantly

18 hydro-based system, it is subject to the variations of

19 weather much more so than a thermal-based system. The

20 benefit of hydro can also become the detriment due to the

21 accumulation or lack of accumulation of snowpack and

22 precipitation. As I have already discussed, with regional

23 energy prices already at levels that had never been

24 experienced before, and with an uncertain water situation,

25 I believe that the actions of the Company in light of the

130

ANDERSON, DI 10
Idaho Power Company

1 circumstances as we found them were reasonable and prudent.

2 Once the Company had knowledge that snowpack would be low

3 and that prices for power supply were not going to decline,

4 the Company took active measures in the form of both supply

5 and demand side actions to reduce the Company's power

6 supply costs. Those actions could not be implemented until

7 after February 2001.

8 Q. Does that complete your testimony?

9 A. Yes.

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131

ANDERSON, DI 11
Idaho Power Company

1 (The following proceedings were had in

2 open hearing.)

3 COMMISSIONER KJELLANDER: And we're ready now

4 for the attorney representing the PUC Staff.

5 MS. NORDSTROM: Thank you.

6

7 CROSS-EXAMINATION

8

9 BY MS. NORDSTROM:

10 Q Good morning.

11 A Good morning.

12 Q On page 3 of your testimony, lines 9 through

13 11, you state that during the period between 1999 and June

14 2001, the business practices related to the review of the

15 regulated operations evolved. Please explain what you mean

16 by "business practices."

17 A What that particular statement refers to is

18 that beginning back in 1999, the risk management process

19 that we had put in place began to expand its role. As I've

20 stated in my testimony, the Risk Management Committee first

21 began in 1996. The intent of the Risk Management Committee

22 was truly focused on the nonregulated operation's venture

23 into the speculative trading business.

24 As we built the expertise in that risk

25 management program, it became evident that some of the

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1 skill sets that we developed as part of the nonregulated

2 piece of the business, some of those skill sets would come

3 to play as we started to look at the regulated side of our

4 business and so from that, as it relates to what happened

5 in the period between 1999 and 2001, what we did was we

6 began taking a much deeper look into the operational

7 aspects of our system.

8 As you know, we are a very hydro dependent

9 organization, therefore, have a very difficult time

10 predicting what our generation capacity is going to be year

11 to year depending upon what the weather looks like;

12 therefore, we decided we would take some of the expertise

13 that we have developed and use that expertise in trying to

14 help us how do we help better manage this portfolio of

15 generating systems that we have for the benefit of the

16 regulated consumer.

17 Q So maybe I missed it, but specifically the

18 business practices were?

19 A The business practices were to look at

20 opportunities that we might be able to do better to manage

21 the system; in other words, take a look at our resources,

22 take a look at our loads, take a look at how we might best

23 hedge the system going forward.

24 Historically, prior to the formation of the

25 Risk Management Committee, the Company had no formal

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1 processes or groups that really took a look at how we

2 managed the system. It was really done by the people that

3 operate our power supply group; therefore, what we did was

4 we brought in outside expertise. That outside expertise

5 provided us some insights as to other products that might

6 be out there for us to better manage those resources, and

7 specifically, I think when you look from 1999 forward, what

8 you saw there was some specific examples of where we

9 actually went out and took a look at the system, saw where

10 we were long, saw where we might be short on a portfolio of

11 the resource and decided how might we best move some of

12 those resources between periods, and so the sense there was

13 we have a resource, how can we better manage it and using

14 the expertise, whether it's Risk Management Committee

15 functions, whether it's traders who know how to acquire a

16 resource the best way, those are the types of processes

17 that evolved between that 1999 and 2001 and it was really a

18 more formalized process than what we've had prior to 1999.

19 Q Did that outside expertise ever recommend

20 creating formal risk management policies and procedures?

21 A There were formal risk management procedures

22 developed for the nonregulated side of the business. In

23 addition to that, as part of the evolution of the regulated

24 side of the business, there was the discussion that focused

25 on we need to take a look at how do we better manage the

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1 system and those processes are currently in place as we're

2 starting to develop and review some of those

3 recommendations.

4 Q So were the formal risk management policies

5 in place during the 2000-2001 PCA period?

6 A I'll go back to the risk management policies

7 and procedures that we had in place beginning back in 1996

8 focused on the speculative non-op side of our business.

9 That was the intent of that business. We had been

10 counseled and guided by a number of outside folks in order

11 to make sure we had those policies and procedures in place

12 prior to implementing that business. As it relates to the

13 regulated side of the business, that was not the original

14 intent of that group.

15 Q So to your knowledge, were there any formal

16 risk management policies in place during the last PCA

17 period for the regulated entity?

18 A It was never the original intent of the Risk

19 Management Committee to focus on the regulated side of the

20 business. That was not the original intent. We did

21 however and were however able to draw upon the expertise of

22 those resources to work with the regulated side of the

23 business. We are in the process of developing those

24 processes and procedures for the regulated side of the

25 business.

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1 Q But they were not in place during the last

2 PCA period; correct?

3 A We did not have formalized policies and

4 procedures related to the regulated side of the business,

5 that's correct.

6 Q Thank you. On page 3 of your testimony,

7 lines 23 and 24, you state that the committee used "other

8 pertinent internal and external data" to make buy and sell

9 decisions. What type of data are you referring to?

10 A One of the things you need to recognize that

11 the committee was comprised of officers of Idaho Power and

12 that officer group comprised decades of experience. A lot

13 of the experience that was drawn upon was their historical

14 knowledge of how the system operated, the implications of

15 weather, how do we best manage the system, when do we run

16 units, when do we not run units. That type of expertise

17 was the type of other data, internal data, that we relied

18 on.

19 As it relates to external data, that data

20 related to activities that were going on outside of our

21 particular service territory, what was happening with other

22 units, those types of things that were taking place. That

23 was the data that would come based on the expertise of that

24 committee. There was a lot of emphasis placed on the past

25 experience of that committee and the expertise that they

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1 brought to the table. They were all long-time industry

2 participants and so it brought a lot of depth to that

3 group.

4 Q Do you feel that their historical expertise,

5 as you called it, is applicable to activities in the open

6 wholesale markets?

7 A I believe that we were represented on that

8 committee by individuals that had expertise in that area,

9 yes, I do.

10 Q What procedures for gathering and analyzing

11 data were in place for the regulated utility?

12 A The process for managing the system is one

13 that is very complicated. First of all, we have to analyze

14 load, we need to analyze the resource and be able to take a

15 forward look on each of those variables, and so there's a

16 combination of groups of individuals within the

17 organization that puts that data together, we roll that

18 data together to put together an overall operations plan,

19 at which point in time we take a look at that operations

20 plan and decide what we might best do to manage that

21 portfolio.

22 MR. RIPLEY: Excuse me, Mr. Anderson, could

23 you talk just a little slower for our court reporter?

24 THE WITNESS: Okay, I will try. I think I

25 finished that thought.

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1 Q BY MS. NORDSTROM: Go ahead.

2 A I think I did.

3 Q Oh. Is the decision to purchase in November

4 2000 for January 2001 or third quarter 2001 a speculative

5 decision?

6 A Let me put in context the November

7 transaction, I think, which is very important. The

8 November transaction was a transaction the committee was

9 looking at as it looked at its portfolio where it indicated

10 that we were short approximately 63 average megawatts in

11 January of 2001. At the same time we were looking at that

12 particular portfolio, we noted that through the balance of

13 the PCA year we had probably excess or we were long

14 generation almost 1,300 megawatts.

15 In looking at that 63 megawatts, the

16 committee discussed at length what should we do with

17 January. We also as we sat in November, we were

18 sitting at a situation where we had only experienced

19 approximately 20 percent of our annual precipitation.

20 Given the fact that we obviously are predominantly a hydro

21 unit or hydro facility, that lack of precipitation at that

22 time or the small amount that had come given what we

23 thought could still come provided a lot of uncertainty at

24 the time.

25 We discussed at length should we hedge,

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1 should we not hedge for that particular month. We had

2 some discussions where we did confirm the fact that we

3 would hedge. We subsequently decided that that is an awful

4 large expenditure at that time given the balance of the

5 length of our system, that it probably would not be a good

6 time to do that given the fact we were at 1,300 megawatts

7 long.

8 As it relates to the November transaction

9 where we sold the first quarter and bought third quarter,

10 you also have to recognize that when you look on average

11 for the third quarter, we were in a net short position, so

12 for that quarter by pushing energy out of the first quarter

13 and moving it into the third quarter, we in essence

14 flattened out our position and in that case we believe that

15 minimizes the risk.

16 As it relates to speculation, our focus is

17 really on the position. If we put price into the equation,

18 we do become speculators and our focus is on the system.

19 Our speculative side of our business is on the nonregulated

20 side and so what we are trying to do is really maintain our

21 system in the best way that we can and the way we can do

22 that is by attempting to flatten out the system as much as

23 we can, taking a broader look rather than truly a rifle

24 shot approach.

25 Q Did an internal audit recommend a better

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1 audit trail in developing comprehensive policies and

2 procedures before and during the current PCA year?

3 A They may have. Can you refer me to something

4 specific?

5 Q I believe this is internal audit report

6 No. 27062288 and 27062299.

7 A Can you -- I don't know the internal audit

8 reports by number, but can you explain to me what the scope

9 of that audit was because the scope may have been

10 specifically for the nonregulated side of the business?

11 MR. RIPLEY: Could counsel provide a copy of

12 the document so that Mr. Anderson could look at it?

13 COMMISSIONER KJELLANDER: I think the request

14 is whether or not counsel can provide a copy of the

15 documents in reference.

16 MS. NORDSTROM: It's my understanding that

17 these documents were confidential and required to be only

18 on site at the Company.

19 MR. RIPLEY: So they don't have one to give

20 me?

21 MS. NORDSTROM: We weren't allowed to take

22 one.

23 THE WITNESS: I can't speculate as to whether

24 that was for the regulated side or the nonregulated side.

25 Q BY MS. NORDSTROM: I believe the title of it

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1 was Energy Trading Operations Review.

2 A There again, I can only speculate what might

3 be in the contents of that report.

4 Q Did the Company have any data or analysis

5 relating to the potential risk or range of future price

6 movements, vis-a-vis the range of potential price movements

7 for the future time periods?

8 A As part of our operations plan development,

9 included in that data is a forward curve that includes

10 prices at the Mid-C, which is the market price that we use

11 in order to evaluate those opportunities.

12 Q Does that include volatility?

13 A Volatility is not included in that report.

14 Q So the perceived risk is a volumetric

15 exposure rather than potential price movement?

16 A Our focus on managing the system is taking a

17 look at the portfolio of generating assets that we have and

18 taking a look at that not from a price perspective but how

19 long or how short are we in a particular period. We

20 believe that bringing price into the equation just creates

21 speculation.

22 Q What basis did the Risk Management Committee

23 have for determining that the period involving the third

24 quarter of 2001 was less risky than January 2001?

25 A As it relates to risk, the focus was how do

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1 we flatten out the system and when we looked at the third

2 quarter, the third quarter was short 163 megawatts and when

3 we looked at the balance of the PCA year for 2001, that was

4 long 1,300 megawatts; therefore, by pulling 100 megawatts

5 out of the first quarter and moving it into the third

6 quarter flattened out our position.

7 Q What factors were considered and discussed by

8 the Risk Management Committee that resulted in the

9 unanimous decision to purchase the hedge in January 2001?

10 A The decisions that were discussed included

11 length in the system, the factors included where we stood

12 from a precipitation standpoint given the fact that it

13 was early on in the period. It's the same factors that

14 were decided upon when we made the same decision to

15 reverse the decision and so it was really a sense of

16 is this the right transaction to do now given the length

17 of our system and so we looked at all the various factors,

18 demand, resource, precipitation, generating capacity and

19 it was the sense that given the magnitude, the 63 megawatts

20 for January, which probably represents less than four

21 percent of our total generating capacity for that

22 particular month and less than about four percent of our

23 load for that month, we felt that that was a number that

24 we could manage. That's why we went back and forth on

25 that decision. We labored on that decision very

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1 significantly because of where we stood with the system.

2 It was a very difficult decision. Every day we meet those

3 decisions they're very difficult with all the various

4 factors that are there we have to consider.

5 Q So there was no additional information that

6 was brought to the Risk Management Committee's attention

7 following the original decision that made the committee

8 change its mind?

9 A The decisions were all made at the same time

10 in the same meeting within the same span of time, so it was

11 all done in the context of that same meeting.

12 Q When you say "span of time," about how long

13 are we talking about?

14 A Our Risk Management Committee meetings run

15 anywhere between an hour to two hours, sometimes longer,

16 but that's generally the case.

17 Q Were there other things discussed in between,

18 other topics?

19 A There were a couple of other topics on the

20 agenda.

21 Q So were there other topics between your first

22 decision and the decision that reversed the original

23 decision?

24 A There were overriding discussions. When we

25 closed the meeting, we wanted to reconfirm the fact that we

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1 were all comfortable with this. You have to understand

2 given the make-up of this committee, this committee is the

3 senior officers of our organization. They all have very

4 pointed views, very significant amount of knowledge of how

5 things work and history of the organization, so you have a

6 lot of individuals that will speak their mind in those

7 meetings and so when we served to wrap the meeting up,

8 there was a sense of that no, maybe this was not right the

9 decision to make and that's why the decision at the time

10 was to reverse that decision and therefore go short into

11 January at that time given the unknowns that we knew at the

12 time.

13 Q I guess the point I'm trying to get to is why

14 wasn't this recorded in the decision minutes that you had

15 changed your mind if it was only a meeting of less than two

16 hours and that was the primary topic to be discussed?

17 A I think the recording issue is a specifically

18 different issue than the decision not to do the hedge and

19 the recording issue is truly a clerical error and that

20 clerical error was mine, so from that standpoint, it wasn't

21 an error as to what was the decision, it was the

22 documentation of that decision.

23 Q What documentation was maintained for that

24 meeting?

25 A We have a set of minutes, we have an ops

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1 plan that showed surplus/deficits. That is the

2 documentation that is retained. To retain all the data

3 that supports these meetings would be volumes and volumes

4 of information and at different times when things come up

5 and what our goal is is that these minutes are not -- we

6 don't view them as, No. 1, a legal record or required

7 record. It's really documentation for our purposes to

8 kind of keep track so we don't rehash things that we may

9 have rehashed in the past and that's the main focus of what

10 those minutes are for.

11 Q Wouldn't part of the purpose of those minutes

12 be to allow review of decisions the Risk Management

13 Committee has made?

14 A One of the emphases on there is to record

15 decisions made by the committee, that is correct, and what

16 I'm indicating is that we did have an error in those

17 minutes, but the activities surrounding the decision I

18 believe is what prevails over what is written in the

19 documentation.

20 Q But wouldn't supporting documents also

21 corroborate the views expressed in the minutes?

22 A That would be one piece of information that

23 you could use, but I think what really corroborates it is

24 what activities took place and the activities that took

25 place were that we elected not to do the hedge at the time

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1 given what we knew at the time.

2 Q Okay, going back to the relative length of

3 the system at the time in November 2000, you indicated that

4 the overall length of the system for the balance of the PCA

5 period was one factor in deciding not to purchase the hedge

6 for January 2001. Does that mean that although the system

7 was short in January, there was excess generation in other

8 months of the year?

9 A That's correct.

10 Q So essentially because you had expected

11 excess generation in March, you chose not to cover a

12 shortage in January; is that correct?

13 A In taking a look at the portfolio, that is

14 correct, but at the same time, there were other factors,

15 one of those being the variability of weather which was one

16 of the primary factors, because at that point in time all

17 indications were that we still had the likelihood of normal

18 precipitation which would have allowed us to manage around

19 the 63 megawatts.

20 Q Has the Company ever purchased a hedge to

21 meet a shortage when it was long for the balance of the PCA

22 year?

23 A I think we probably have. I can't state one,

24 but I believe we probably have done that and there were

25 probably factors that were there that predicated that

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1 happen.

2 Q Didn't the Company in fact purchase a hedge

3 for January 2001 just one month later in December?

4 A First of all, the Risk Management Committee's

5 focus is on the long-term transactions. The system

6 operators have the ability to manage both current month

7 and prompt month and so no, there was not a hedge that

8 was dictated by the Risk Management Committee at that

9 time. That was more as to how do we meet system

10 requirements.

11 Q So who made that decision, then?

12 A That is an operating decision that is granted

13 to the operators of the system, both for the current month

14 and prompt month. They have a 30-day ability in which to

15 do that.

16 Q So the Risk Management Committee wasn't

17 involved in covering the shortage in generation for

18 January?

19 A That is an operating decision that is made at

20 the time given what the current system requirements are at

21 that time, that's correct.

22 Q Was the system still in a net long position

23 at that time on a portfolio basis for the balance of the

24 PCA period?

25 A Yes, they were.

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1 Q Did the Risk Management Committee consider

2 the price of the hedge prior to making a unanimous decision

3 to purchase the hedge?

4 A Price is one of the factors that is obviously

5 involved in that decision, but the focal point of the

6 decision is the length of the system, taking a look at how

7 do we manage the system resource.

8 Q Then the cost of the hedge was information

9 considered by the committee before the original decision

10 was made; is that correct?

11 A Cost was one factor.

12 Q What was the assumption in the presentation

13 regarding water conditions in the months of December,

14 January and February that led to the decision to proceed

15 with the hedge initially?

16 A It was -- we were still anticipating normal

17 water at that time.

18 Q Is it your testimony that the possibility of

19 above normal snowpack and water conditions was a primary

20 factor to consider in reversing the decision to hedge?

21 A I don't think I've ever said above normal

22 snowpack was a consideration. I think we've been

23 discussing normal snowpack. Normal or slightly below is

24 what I've got in my testimony.

25 Q So above normal snowpack was never discussed

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1 or considered by the Risk Management Committee?

2 A It was the indication at that time that the

3 likelihood of above normal snowpack was probably not a very

4 likely scenario. We were forecasting at that point in time

5 a close to normal precip at that time given the information

6 that we had available to us.

7 Q But doesn't your testimony also say slightly

8 below normal water conditions were predicted as well?

9 A That is the scenario in which we made those

10 decisions.

11 Q And how recent were those predictions made in

12 reference to your November 21st Risk Management Committee

13 meeting?

14 A The process of putting the operations plans

15 together is approximately a week to two-week process to get

16 all the pertinent data put together. My recollection is

17 that that date was probably towards the end of October,

18 early November information.

19 Q If it takes a week to two weeks to prepare

20 those operating plans, does that allow the committee time

21 to respond to changing market conditions in a volatile

22 market?

23 A Our focus is predominantly on the long-term

24 transactions for the system. That's where the system is

25 granted the latitude in which to manage both the current

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1 month and the prompt month activity for that very reason is

2 to take a look at those changing conditions.

3 Q Directing your attention to page 6,

4 line 17 to the top of page 7, in reference to your

5 statement about "risk to falling market price changes," did

6 you or the committee believe that Idaho Power Company would

7 be at risk if market prices fell in December through

8 February?

9 A What our focus in that particular situation

10 was should we increase our length, does that make any sense

11 to increase our length in a period of time when we're

12 looking at a shortage; therefore, what we were really

13 looking to do is how do we flatten out the position and our

14 ability to flatten out the position was not to execute that

15 hedge at that time.

16 Q Are you saying that long-term prices aren't

17 subject to rapid change and therefore shouldn't be

18 considered?

19 A No, I'm not saying pricing should not be

20 considered, but if our emphasis is on managing the system,

21 which is what our focus has been for the operating side of

22 the portfolio, then we have to first look to the system and

23 look at its requirements.

24 Q Did you or the committee believe that market

25 prices would fall for the upcoming months?

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1 A We truly do not try to guess what the market

2 is. There are people out there that can do that and that's

3 what our nonregulated side of the business is trying to

4 do. That is not the focus of the regulated side of the

5 business.

6 I might add, too, though, I guess along those

7 lines and I'd just use this as an example because I believe

8 a lot of folks are aware of it, I think California

9 attempted to do some of those things and today they're

10 paying $40 million a month more than they would otherwise

11 have been because of the long-term contracts they entered

12 into in advance of and I think what they might have been

13 trying to do is guess the market price. Our focus is not

14 to guess the market price.

15 Q I guess one of the considerations for the

16 January hedge, it was my understanding from your testimony,

17 was that price had been considered.

18 A Is a consideration, that's correct, but as I

19 also emphasized, the focus is on the balance of the system,

20 how do we manage the portfolio of assets that we have.

21 Q Are you saying that system reliability, not

22 price risk management, is therefore the focus of the Risk

23 Management Committee?

24 A We feel that reliability is a very important

25 issue and that's one of our primary charges is to assure

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1 reliability of the system. The 63 megawatts in January was

2 a number that we felt at that time given the flexibility of

3 our hydro system that we had the ability to manage around,

4 that's correct.

5 Q Did you or the committee ever consider or

6 acknowledge the risk to Idaho Power Company and ratepayers

7 if prices continued to rise and if water conditions did not

8 improve?

9 A But you could also say the same thing if

10 prices were to fall and you entered into long-term

11 contracts, so what we trying to do was focus on the

12 portfolio. Yes, price is a consideration, but prices can

13 go up and they can go down, and our focus is trying to

14 focus on what is the system and trying to meet the

15 reliability of the system requirements.

16 Q Okay, I understand that, but did the

17 committee consider what would happen if those two events

18 occurred, if prices continued to rise and if water

19 conditions didn't improve?

20 A Our operations plan has the ability and is a

21 number that shows up on our operations plan, shows what the

22 impact is on the PCA with the current portfolio of

23 requirements that we have, so yes, we know what that number

24 looks like, but if we begin to get into the price guessing

25 game, then we become speculators and we are trying to

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1 manage the system and I know that -- I think that's a

2 difficult thing to do that if I had hindsight, would I do

3 some things differently, very much so, but we don't have

4 that ability to be able to have the hindsight in which to

5 say which way prices went. All we have is the best data

6 available at the time that we do our transactions in a

7 real-time mode.

8 Q I guess my point was that price volatility

9 and water conditions are the two boogeymen that are out

10 there that the system is vulnerable to and I'm just

11 wondering if the Risk Management Committee ever considered

12 what would happen if both of these things happened at the

13 same time.

14 A Those factors are included in our operations

15 plan. Those items are included. We are aware of those

16 implications.

17 Q Okay. Given the risk acknowledged by

18 Mr. Gale in his testimony of poor water conditions for a

19 predominantly hydro-based system and the resulting need to

20 rely heavily on the market, do you think it was wise not to

21 hedge that risk when the Company was vulnerable to

22 extremely high market prices?

23 A First of all, we get the final hydro data

24 sometime in February, March, April time frame and until we

25 have that information, it's very difficult to predict what

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1 the output of our hydro units are going to be, which points

2 to the challenges of managing a hydro system and so with

3 that, there is inherent risk built into that variability in

4 weather, and I think as discussed before with Mr. Said's

5 testimony, one of the reasons for the PCA is to help manage

6 some of that variability.

7 Q Do you believe that it is appropriate for the

8 Risk Management Committee to speculate about whether hydro

9 conditions will be good or bad?

10 A We don't speculate. We rely on independent

11 third-party resources for what the hydro conditions are

12 going to be appear to be. We use that data and run that

13 data through our models and so we do not attempt to

14 speculate on weather conditions. We try to use independent

15 third-party resources in which to determine what that is

16 going to be.

17 Q Do you believe the Risk Management Committee

18 should identify, quantify and acknowledge all possible

19 risks and take actions necessary to ensure a reasonable

20 level of protection against such risk?

21 A I think the Risk Management Committee's

22 charge is to evaluate all the conditions that are going to

23 impact the system and truly try to manage that to the best

24 of the ratepayer.

25 Q On page 7, lines 19 through 24, you indicated

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1 that there was no formalized review of the committee

2 meeting minutes in November 2000. When was this review

3 subsequently implemented?

4 A I believe that review process was implemented

5 in March or April of this year.

6 Q Have there been any other documentation

7 changes that the Risk Management Committee has implemented

8 since November 2000?

9 A Well, from a documentation standpoint, the

10 operations plan has continued to evolve and got more

11 additional data that has been input into that model to

12 continue to attempt to refine that and we have ongoing

13 projects that we're working on in trying to refine that

14 process. We have also taken steps to redo the Risk

15 Management Committee make-up for the regulated side of the

16 business. We have changed some of the members on that

17 committee to have a complete focus on Idaho Power.

18 Q On pages 8 and 9 of your testimony, you

19 discuss the follow-up process to assure follow-through of a

20 Risk Management Committee decision. If the follow-up

21 process failed, would there be any written directive

22 authorizing the traders to execute the transaction?

23 A Can you repeat that to make sure I understand

24 your question?

25 Q Sure. On pages 8 and 9 of your testimony,

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1 you discuss the follow-up process to assure follow-through

2 of an RMC decision. If the follow-up process failed, would

3 there be any written directive authorizing the traders to

4 execute the transaction?

5 A Yes. We have two modes in which we

6 communicate with the traders when a formal decision has

7 been made to hedge for the system. It's either in written

8 form or electronic form via e-mail or in written memo

9 format. That is the documentation that the trader requires

10 before it implements a hedge transaction.

11 Q Is it fair to say that no transaction would

12 have occurred if the Risk Management Committee failed to

13 send a written authorization to traders?

14 A For a transaction that was approved by the

15 Risk Management Committee, that is correct.

16 Q During the 2000-2001 PCA year, isn't it

17 accurate to state that there was one Risk Management

18 Committee that provided oversight for both the nonregulated

19 and the regulated activities of IDACORP?

20 A That's correct, but I would also add to that

21 that committee focused on Idaho Power regulated operations

22 and spent the time focus on there and then switched and

23 focused on nonregulated activities and when regulated

24 activities were discussed, the focus was entirely on the

25 regulated operations without regard to anything that was

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1 taking place on the non-operations side.

2 Q Is it correct to say that before these Risk

3 Management Committees were separated that Ida-West Energy

4 and its president was also a member of the RMC?

5 A Randy Hill who is the president of Ida-West

6 did sit on the committee and the thought process behind

7 that was because Randy Hill has an extensive amount of

8 knowledge about what is going on in the industry and the

9 region, he operates hydro plants and so with his expertise,

10 we thought it was a very valuable resource in which to have

11 on that committee to help support the rest of the committee

12 members.

13 Q Were the goals of the regulated and

14 nonregulated operations the same?

15 A The regulated focus of the Risk Management

16 Committee was focused on how do we manage the system. The

17 focus of the nonregulated side of that was focused on

18 ensuring that the non-op side of the business adhered to

19 and managed to limits, credit limits, trading limits and

20 discussed trading strategies.

21 Q So the goals were not the same?

22 A That's correct.

23 Q Please explain how pricing and cost control

24 goals of Ida-West Energy, a subsidiary in the business of

25 independent power project development, selling power to a

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1 utility are consistent with the goals of Idaho Power which

2 is a utility purchasing and selling power to meet its

3 customer's needs.

4 A I don't believe they probably are the same.

5 They do have different objectives.

6 Q Were the prices during the end of June 2000

7 through August 2000 higher than historical market prices in

8 1999 for the same months?

9 A I'd have to look at a forward curve to take a

10 look at that. You said 2000 against '99?

11 Q Correct.

12 A I would speculate that they might be, but I

13 couldn't tell you without looking at a forward curve.

14 Q How did the Risk Management Committee weigh

15 the regulatory changes in the California market and market

16 prices that were higher than historical levels?

17 A Well, obviously, the California situation had

18 an impact on the market prices in the Northwest. I think

19 at the time that we evaluated the system operations, the

20 focus there continued to be on the system and to the extent

21 we had to go to the market that there were going to be

22 impacts, possibly, on those costs because of the impact

23 that California was having on the Mid-C pricing.

24 Now, at the time that we looked at, continued

25 to look at, the system, the same variables were in effect,

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1 weather, load, all those factors were the same and to try

2 to bring pricing into the equation, we knew that that may

3 have an impact, but we were still focused on how do we

4 manage the system and keep it as balanced as we could.

5 Q Is it true that term contracts represent open

6 trading positions?

7 A Term contracts depending on the situation in

8 which they are used could be considered open contracts,

9 open positions.

10 Q Is it correct that open positions are

11 included in the stop loss limits?

12 A I don't believe that has anything to do with

13 my testimony and in fact, that stop loss is not an issue

14 for the regulated side of the business.

15 Q The reason why I'm asking you is because

16 you're a member of the Risk Management Committee that deals

17 with these issues. Procedures and safeguards are at issue

18 in this case.

19 MR. RIPLEY: Are you now asking questions of

20 Mr. Anderson that are not related to his direct testimony?

21 Might I inquire?

22 COMMISSIONER KJELLANDER: Yes, you can

23 inquire. I think the question was, is that an objection?

24 MR. RIPLEY: I object that counsel is now

25 asking questions outside the scope of his testimony.

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1 MS. NORDSTROM: But I believe his testimony

2 does cover the procedures and safeguards that were in

3 effect at the time that the November transaction took place

4 and these are part of the considerations that were reviewed

5 at that time.

6 COMMISSIONER KJELLANDER: Any response?

7 MR. RIPLEY: Renew the objection.

8 Mr. Anderson's testimony is related to the November

9 transaction.

10 COMMISSIONER KJELLANDER: We're going to

11 allow the question and encourage a response.

12 THE WITNESS: Can you repeat the question,

13 please?

14 Q BY MS. NORDSTROM: Yes. Is it correct that

15 open positions are included in the stop loss limits?

16 A I'm not sure I can answer that question, to

17 tell you the truth and I'm not sure in what context you're

18 asking the question. Term contracts can be considered open

19 positions depending on whether or not you could have hedged

20 those out against your physical positions. You could have

21 done a number of things with that position. I'm just not

22 sure what context you're asking the question in regards to

23 a stop loss limit.

24 Q From your understanding of stop loss limits,

25 during the last PCA year were stop loss limits established

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1 for all electric transactions combined or were they

2 separated out for the regulated and nonregulated

3 activities?

4 A There are no stop loss limits for the

5 regulated side of our business. There are stop loss limits

6 for the nonregulated side of our business.

7 Q Do you believe that examining forward market

8 implied volatility and its impact on price risk for

9 regulated customers injects price view into the risk

10 management decision?

11 A I believe that volatility has an impact on

12 pricing. I believe that volatility has an impact on the

13 market prices. I guess from a standpoint of taking a price

14 view, I think that that combined with the forward curve

15 does take a price view and I think it also does speak to

16 speculation.

17 Q Why would the market's view of the risk of

18 potential price ranges and implied volatility therein be

19 injecting a corporate price view?

20 A I think that when we are trying to take a

21 look at how we manage the system, we are taking a look at

22 the resources that we have available to us and that is in

23 the form of generation, in the form of CSPP contracts and

24 in the form of potential purchased power requirements

25 depending on what demand is. By taking a price view, we

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1 believe that injects speculation. What we think we can

2 best manage is the resource and manage around that

3 resource. Price is part of that consideration, but it is

4 not the primary driver of that decision making.

5 Q So is the market's view of potential price

6 ranges a corporate price view?

7 A In our case, we look at the forward curve as

8 our market price.

9 Q Then isn't the implied volatility the

10 potential range of those prices?

11 A Implied volatility does provide a range in

12 which that price could move.

13 Q Is that the market's perception of that

14 range?

15 MR. RIPLEY: Mr. Chairman, I'm going to

16 object. Again, we've gone so far outside the bounds of Mr.

17 Anderson's direct and frankly, I see no relevancy to the

18 issues that are before the Commission today. This is a

19 very interesting academic discussion, but how in the world

20 does it tie to the issues that the Commissioners must

21 decide in this proceeding? I will object. She's far

22 outside the bounds of any reasonable cross-examination.

23 COMMISSIONER KJELLANDER: And your response?

24 MS. NORDSTROM: Yes, the focus of

25 Mr. Anderson's testimony was to discuss things that were

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1 considered at the time of the November event, trading

2 event, and these were things that they were considering or

3 not considering and Staff is just trying to elicit what

4 they were basing their decisions on, which is the focus of

5 this $8 million in dispute.

6 MR. RIPLEY: If counsel wants to tie her

7 questions to did the Company consider these particular

8 issues in the November transaction, there would at least be

9 some semblance of relevancy, but the generalized way in

10 which counsel is asking the question obviously exceeds far

11 outside the bounds of Mr. Anderson's direct testimony.

12 MS. NORDSTROM: Staff will withdraw its

13 question.

14 COMMISSIONER KJELLANDER: Okay.

15 MS. NORDSTROM: Staff has no further

16 questions at this time.

17 COMMISSIONER KJELLANDER: Mr. Richardson.

18 MR. RICHARDSON: Just a couple,

19 Mr. Chairman.

20

21 CROSS-EXAMINATION

22

23 BY MR. RICHARDSON:

24 Q Good afternoon, Mr. Anderson.

25 A Yes, it is.

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1 Q You stated in response to a question from

2 Ms. Nordstrom that the committee changed members so that

3 the committee has a complete focus on Idaho Power?

4 A That's correct.

5 Q How did the committee do that? Who got

6 bumped off?

7 A What we did for the Idaho Power committee, we

8 restricted the make-up of the Idaho Power Risk Management

9 Committee to IDACORP or Idaho Power officers only,

10 therefore, eliminating any other subsidiary representation

11 on that committee.

12 Q Who got bumped off was the question?

13 A Randy Hill was bumped of and Rich Riazzi was

14 bumped off, those two individuals, I believe, and Ric Gale

15 was added as was Bart Kline and Jan Packwood was also

16 bumped off.

17 Q Why was Jan Packwood bumped off?

18 A Because he's going to be participating on the

19 IDACORP Energy Risk Management Committee and there was a

20 sense we did not want anybody on that committee that's also

21 on the Idaho Power committee other than one person. We

22 have one consistent member between committees at this time

23 just for consistency.

24 Q Who is that?

25 A That is LaMont Keen.

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1 Q So you have two Risk Management Committees

2 now?

3 A We actually have three. We have an IDACORP

4 Risk Management Committee, we have an Idaho Power Risk

5 Management Committee and we have an IDACORP Energy Risk

6 Management Committee.

7 Q Now, you're the chairman of the Idaho Power

8 Risk Management Committee?

9 A I was the chairman of the Idaho Power Risk

10 Management Committee. John Prescott is now the chairman of

11 the Idaho Power Risk Management Committee, but during the

12 time that we are speaking, at least with respect to my

13 testimony, I was the chairman of the Risk Management

14 Committee.

15 Q Okay, on page 2 of your testimony, you state

16 I am the chairman of the Risk Management Committee.

17 A And at the time I did my testimony, that was

18 true.

19 Q So do you need to make a change there?

20 A I'd defer to my counsel. I'm not sure what

21 the legal requirements are.

22 Q Your testimony says I am the chairman, but

23 your testimony today is you are not the chairman; correct?

24 A That's correct.

25 Q Okay. Does the committee have bylaws or

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1 operate under any procedural regulations such as Robert's

2 Rules of Order?

3 A No.

4 Q How does the committee govern itself?

5 A The committee governs itself, the chairman

6 and in this particular case myself, we set an agenda, we

7 have a meeting, we document some of the discussions that

8 take place and we move on. It was an informal group that

9 was originally set up to focus on the nonregulated side of

10 the business and then evolved over time to consider some of

11 the regulated implications of risk that was identified that

12 we should be taking a look at.

13 Q You stated in your testimony that a majority

14 vote is required, who made the decision that a majority

15 vote is required?

16 A We do have in the policies and procedures

17 related to the risk management program at the nonregulated

18 side of the business, we have policies and procedures that

19 require a majority vote on decisions.

20 Q But we're talking about the Idaho Power

21 Company.

22 A And at the time we're talking about, Idaho

23 Power was one and the same, Idaho Power nonregulated and

24 regulated were one and the same, entity.

25 Q So it's those policies and procedures that

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1 governed the Risk Management's procedures?

2 A With the emphasis on the nonregulated side of

3 the business, that's correct.

4 Q Is there weighted voting? Do all the members

5 have one vote?

6 A Yes, they do.

7 Q Were you elected chair or were you appointed

8 chair?

9 A I believe I was appointed.

10 Q And you also take minutes for the meetings;

11 correct?

12 A That's correct.

13 Q Now, I think Connie is probably the only

14 person I know of who can keep up with your fast-paced

15 speaking style, do you still take minutes for the meetings?

16 A I did up until the time we broke out the

17 committees. At this point in time we have a representative

18 on the committee that now takes the Idaho Power minutes.

19 Q And is that representative also a chairman of

20 the committee?

21 A Not the chairman but a member.

22 Q When you took the minutes here for the

23 meeting in question on November 21, when did you first

24 realize that there was an error?

25 A I think my recollection of the error really

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1 wasn't brought to my attention until the Staff of the

2 Commission brought that up.

3 Q So how many months elapsed between the time

4 of the meeting and when you first realized there was an

5 error?

6 A I don't know how many months that was. I

7 think it was probably four or five, four.

8 Q In your testimony on page 5, you go through

9 some detailed explanations for the decision that was not

10 recorded in the minutes.

11 A Correct.

12 Q And were those all just based on your

13 recollection, then?

14 A Those were based on my recollections of the

15 discussions that took place at that meeting.

16 Q And when did you put these recollections to

17 paper?

18 A These recollections were put to paper at the

19 time I prepared my testimony.

20 Q Which was when?

21 A Larry, can you help me?

22 MR. RIPLEY: Hang on. Could we have a

23 moment, please?

24 COMMISSIONER KJELLANDER: We'll go at ease.

25 (Pause in proceedings.)

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1 COMMISSIONER KJELLANDER: We'll go back on

2 the record.

3 THE WITNESS: On or about June 21st.

4 Q BY MR. RICHARDSON: Did you have assistance

5 in preparing your testimony?

6 A Pardon?

7 Q Did you have assistance in preparing your

8 testimony?

9 A I prepared the majority of it myself. I had

10 a little assistance.

11 MR. RICHARDSON: That's all I have,

12 Mr. Chairman.

13 COMMISSIONER KJELLANDER: Thank you,

14 Mr. Richardson, and I think at this point what we'll do is

15 we'll go ahead and we'll break for lunch until

16 approximately 1:30. At that time we'll return and,

17 Mr. Anderson, you will still be on the stand and you'll be

18 at that point, I believe, ready for questions from the

19 Commission and then we'll be ready for redirect, so with

20 that, we will go off the record and break for lunch.

21 (Noon recess.)

22

23

24

25

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