HomeMy WebLinkAbout20010913Puc8301.v1.doc
1 BOISE, IDAHO, THURSDAY, AUGUST 30, 2001, 9:00 A. M.
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4 COMMISSIONER KJELLANDER: Well, good
5 morning. It looks like we're ready to go back on the
6 record, so we'll be back on the record and as we left
7 things yesterday, I believe that we were awaiting some
8 additional rebuttal testimony and I notice that it has
9 shown up in the form of six pages for Ms. Hoyd and two
10 pages for Mr. Gale, so I believe that we are ready now for
11 the Company to put on its rebuttal testimony for those
12 final two witnesses.
13 MR. RIPLEY: Thank you. We'd call Ms. Hoyd.
14
15 SHARON G. HOYD,
16 produced as a rebuttal witness at the instance of the Idaho
17 Power Company, having been previously duly sworn, resumed
18 the stand and was further examined and testified as
19 follows:
20
21 DIRECT EXAMINATION
22
23 BY MR. RIPLEY:
24 Q Would you state your name for the record,
25 please?
557
CSB REPORTING HOYD (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 A Sharon Hoyd.
2 Q And are you the same Sharon Hoyd that has
3 presented direct testimony in this proceeding?
4 A Yes.
5 Q And have you had cause to be prepared for
6 this proceeding certain rebuttal testimony?
7 A Yes.
8 Q And does that rebuttal testimony consist of,
9 to begin with, seven pages of testimony?
10 A Yes.
11 Q And if I asked you the questions that are set
12 forth in that testimony, would your answers be the same
13 today?
14 A Yes.
15 Q And in that testimony, do you also introduce
16 and identify Exhibit 28?
17 A Yes.
18 Q And in addition to that, Ms. Hoyd, have you
19 then had cause to be prepared some additional rebuttal
20 consisting of six pages?
21 A Yes.
22 Q And if I asked you the questions that are set
23 forth in the additional rebuttal prefiling, would your
24 answers be the same?
25 A Yes.
558
CSB REPORTING HOYD (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 Q And you have no exhibits attached to the
2 additional rebuttal?
3 A No.
4 MR. RIPLEY: With that, we would ask that
5 Ms. Hoyd's direct rebuttal and her additional rebuttal be
6 spread upon the record as if read, indicating Exhibit 28
7 and would tender the witness for cross-examination.
8 COMMISSIONER KJELLANDER: And without
9 objection, we will do just that and move forward now to --
10 MS. NORDSTROM: Staff has no objection so
11 long as the Company has no objection to our additional
12 direct testimony. I believe he reserved that objection
13 yesterday.
14 COMMISSIONER KJELLANDER: Okay.
15 MR. RIPLEY: I don't quite understand. Is
16 there something -- I'm sorry, I didn't hear.
17 MS. NORDSTROM: I'm sorry, I thought that he
18 reserved his objection to the admission of additional Staff
19 direct testimony yesterday until this morning and I don't
20 object if he doesn't object.
21 MR. RIPLEY: Oh, I see. Of course, we think
22 this is an accommodation and we have no objection to the
23 additional.
24 MS. NORDSTROM: And neither does Staff.
25 MR. RIPLEY: Now we got that out of the way.
559
CSB REPORTING HOYD (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 (The following prefiled rebuttal and
2 additional rebuttal testimony of Ms. Sharon Hoyd is spread
3 upon the record.)
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CSB REPORTING HOYD (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 Q. Please state your name, business address and
2 present occupation.
3 A. My name is Sharon G. Hoyd and my business
4 address is 350 N. Mitchell, Boise, Idaho. I am employed by
5 IDACORP Energy, a subsidiary of IDACORP, as Vice President
6 of Finance.
7 Q. Have you previously submitted prefiled direct
8 testimony in this proceeding?
9 A. Yes.
10 Q. What is the purpose of your testimony today?
11 A. The purpose of my testimony is to address
12 assertions made by witnesses Terri Carlock and Anthony
13 Yankel in their direct testimony filed in case Nos.
14 IPC-E-01-7 and IPC-E-01-11 related to the calculation of
15 total cost for non-system purchases and the reasonableness
16 of the pricing mechanism used for transfer prices.
17 Q. In page 4 of his direct testimony Mr. Yankel
18 asserts that from his review of the data "it can generally
19 be concluded that the most expensive purchases have been
20 what is labeled as Intramonth, followed by Real Time, with
21 Term being the least expensive". Do you agree with this
22 conclusion?
23 A. No. Mr. Yankel is drawing his conclusion from
24 the review of only two months of data, the month of April
25 2000 and the month of December 2000. This is too selective
561
HOYD, DI-REB 1
Idaho Power Company
1 and does not encompass nearly enough data to permit a valid
2 conclusion. In IPUC Staff Exhibit No. 127, Staff's
3 calculation of the costs associated with the "November
4 transaction" addresses this very point. The term price in
5 December for January was substantially higher than the
6 prices for day-ahead energy during January as can be seen
7 in the exhibits sponsored by Dr. Peseau and Mr. Gale. The
8 relative positions of the forward market prices and the
9 current month market prices are changing constantly and to
10 make general statements that one is generally higher than
11 the other is clearly not supported by what actually occurs.
12 Q. On page 6, line 5 of Ms. Carlock's direct
13 testimony, Ms. Carlock states "Staff proposes to modify the
14 pricing mechanism... to more accurately reflect the total
15 cost. The non-system purchases were less costly overall
16 than the system purchases at market index." Are Staff's
17 calculations of total cost accurate?
18 A. No. There are two errors with Staff's
19 approach to total cost associated with the non-system
20 purchases.
21 First, the data used to calculate total cost
22 was incomplete. In the calculation of weighted average cost
23 the IPUC Staff included only the cost of energy related to
24 the transactions they selected. Other costs associated with
25 acquiring energy to supply the Idaho Power system, including
562
HOYD, DI-REB 2
Idaho Power Company
1 transmission costs, operating expenses, ancillary service
2 costs, broker fees and the cost of credit, were not
3 considered. For instance, Staff included the cost of energy
4 related to transactions delivered in locations across 16
5 states and 2 Canadian provinces. Much of that energy could
6 not have been physically delivered to the Idaho Power system
7 due to transmission constraints. Assuming, however, that the
8 energy could have physically made it to the Northwest from
9 all these locations, it would have to be wheeled over
10 multiple transmission paths incurring costs at each step
11 along the way. For example, during almost every month of
12 the PCA period, Idaho Power had non-operating transactions
13 delivered at Ault, a delivery point in Colorado. Barring
14 any transmission constraints, getting the energy from
15 Colorado to Idaho would require four separate wheels, or,
16 transmission charges. The total cost for transmission
17 related to those transactions would have been approximately
18 $17 dollars per MWh plus 10% of the energy cost. In a high
19 priced month like December 2000, this would represent 16% to
20 17% of additional costs associated with the transaction.
21 During periods of lower prices such as May 2000, this cost
22 would add an additional 50% to the energy price. During the
23 2000-2001 PCA year alone, the non-operating business paid
24 $55,839,701 in transmission expense and booked a credit
25 reserve of $21,682,000. In March 2001, an additional
563
HOYD, DI-REB 3
Idaho Power Company
1 $20,173,900 was booked against unpaid receivables related
2 to November and December 2001 non-operating transactions.
3 These costs were not considered in Staff's calculations.
4 The second error in Staff's approach is the
5 mismatching of non-system and system transactions. In
6 effect, Staff has compared apples to oranges. For the
7 period April 2000 through November 2000 and for real-time
8 transactions in the months of December 2000 through
9 February 2001, Staff has compared monthly weighted average
10 operating prices to monthly weighted average non-operating
11 prices. By using monthly averages, Staff has not taken
12 into account the volatility of electricity prices between
13 days and hours. As is well documented, the electricity
14 markets are extremely volatile day to day and hour to hour.
15 The price of energy for one hour or day is not indicative
16 of the price for a different hour or day. Comparing
17 monthly weighted average prices from one portfolio to the
18 next, without regard for the actual days or hours of the
19 specific transactions, produces a misleading result not
20 representative of the actual price paid.
21 Additionally, as previously discussed,
22 utilizing the prices of transactions delivered across a
23 third of the United States and Canada as a relevant
24 comparison to transactions occurring at Mid-Columbia will
25 clearly produce a nonsensical result. The volume of
564
HOYD, DI-REB 4
Idaho Power Company
1 non-operating transactions expanded by 68% from 1999 to
2 2000 by increasing the number of counterparties, the types
3 of energy products and geographic regions. This expansion
4 resulted in the non-operating book of business assuming
5 more risk, such as the credit risk of new counterparties
6 and market risks of new regions. By setting the transfer
7 prices between operating and non-operating at the weighted
8 average of all of these transactions, the utility is
9 subjected to the risks, volatilities and costs of other
10 markets outside of the physical markets available for
11 actual supply to the Idaho Power system.
12 Q. If Staff has not represented total cost
13 accurately for purposes of their "lower of cost or market"
14 calculation, what has Staff done?
15 A. Staff has chosen an after-the-fact market
16 basket, or portfolio, of transactions specific to the
17 non-operating book of business. Essentially this creates
18 another surrogate market index - an index specific to the
19 IDACORP Energy book of business.
20 The Staff recommendation results in an
21 approach where they can retroactively and selectively choose
22 the market in which they believe Idaho Power should price
23 transactions. In the case where the non-operating surrogate
24 market is favorable, Staff contends the transfer price
25 should be the non-operating surrogate index. Where the Mid-
565
HOYD, DI-REB 5
Idaho Power Company
1 C market index is more favorable, Staff contends the Mid-C
2 index should be used as the surrogate. In this situation,
3 all potential benefits associated with the risks of the non-
4 operating transactions are passed on to the utility
5 operation without the utility operation assuming any of the
6 risks. This is clearly not a commercially reasonable
7 practice or a practice condoned by regulation. Nor was it
8 an outcome contemplated by the parties or Staff when the
9 Commission approved the operating/non-operating
10 relationship.
11 Q. In Ms. Carlock's direct testimony page 6
12 line 1, she states the market price is not reflective of a
13 reasonable price surrogate between the system and
14 non-system. Do you agree?
15 A. No. The key to making comparisons to any
16 benchmark is using relevant transactions (comparing apples
17 to apples). In Exhibit 28, I have charted the variance
18 between the Mid-C pricing methodology and the weighted
19 average of non-operating transactions as calculated by staff
20 for all months. In addition I have charted the variance
21 between the Mid-C pricing methodology and the weighted
22 average of all relevant non-operating transactions (those
23 transactions occurring on the same day, same hours and at
24 relevant system locations). As illustrated in the chart,
25 the wide swings in cost month-to-month using the erroneous
566
HOYD, DI-REB 6
Idaho Power Company
1 Staff methodology could indicate the Mid-C index is no
2 longer relevant. However, by including only the relevant
3 transactions, the variance from Mid-C month by month is
4 much smaller.
5 Q. If you apply a methodology using the weighted
6 average price of the relevant non-operating transactions for
7 pricing transactions between operating and non-operating for
8 the 2000-2001 PCA period would it have resulted in lower
9 operating costs to Idaho Power Company's retail customers?
10 A. No. It would have resulted in increased
11 system operating costs of $15,851,236.76 and therefore a
12 corresponding increase in costs for the Idaho retail
13 customers.
14 Q. Does this conclude your testimony?
15 A. Yes.
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567
HOYD, DI-REB 7
Idaho Power Company
1 Q. Ms. Carlock states in her additional direct
2 testimony that she does not agree with the methodology you
3 used for comparing the relevant transactions in your
4 rebuttal. Why did you use the methodology Ms. Carlock
5 questions?
6 A. The purpose of the calculations and exhibit
7 included in my rebuttal testimony was purely and only to
8 provide an indication that Mid-C continues to be the
9 relevant index for pricing transactions between operating
10 and non-op operating books. I purposefully used the same
11 methodology in my calculations that Ms. Carlock used in
12 calculating the $47 million she alleges was overcharged to
13 the PCA accounts for day-ahead transactions in order to
14 keep my comparisons as consistent with what had been
15 discussed in the record up to that point. I do not agree
16 that any of the methodologies put forward by Staff arrive
17 at accurate cost figures for purposes of pricing
18 transactions between operating and non-operating books.
19 Q. Has Ms. Carlock used the information provided
20 to her by Idaho Power Company correctly in her calculations
21 on Exhibit No. 133?
22 A. No. Ms. Carlock has misinterpreted and
23 misapplied the data provided to her.
24 Q. How has Ms. Carlock misinterpreted the data?
25 A. Ms. Carlock incorrectly interprets the data
supplied to her to be relevant for transfer prices between
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HOYD, ADDITIONAL-REB
Page 1 of 6
1 operating and non-operating. The data provided by the
2 Company and used in Exhibit No. 133 was a listing of non-
3 operating transactions, volumes and energy prices occurring
4 in the day-ahead markets that noted a delivery point, for
5 purposes of the transaction, of the IPC system. What the
6 delivery point generally indicates on these transactions is
7 the location at which the selling party is required to
8 deliver the energy. The data does not include any ancillary
9 charges associated with these energy transactions, nor does
10 the summary of transactions listed indicate that this is all
11 of the day-ahead energy delivered into the IPC system.
12 There are large quantities of other day-ahead transactions
13 that resulted in delivery to the IPC system. In these other
14 transactions the selling party was required to deliver at
15 non-IPC border points and the non-operating book of business
16 then purchased transmission to allow for delivery of this
17 energy to the IPC system. The data also did not indicate
18 whether or not any or all of the energy reflected in these
19 transactions was used to balance the operating system or
20 the non-operating position, or how any additional energy
21 requirements of the IPC system was met.
22 Q. How has Ms. Carlock misapplied the data?
23 A. In any comparative analysis it is important
24 to ensure that apples are being compared to apples. Ms.
25 Carlock has deviated from this important analytical tenet in
several ways. One example is that Ms. Carlock has, again,
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HOYD, ADDITIONAL-REB
Page 2 of 6
1 applied a monthly average methodology to a daily market
2 phenomenon, not taking care to ensure that she is comparing
3 prices reflective of the relevant daily timeframe. Given
4 the material disparities that can occur from day to day in
5 both volumes and prices, the monthly average methodology
6 could inject substantial error into the calculation.
7 Q. Given time, could you provide additional
8 calculations that would show Ms. Carlock's new analysis to
9 be invalid?
10 A. Absolutely. As has been clearly evidenced in
11 this case, once one departs from an independent index such
12 as Mid-C, there are as many ways to interpret and apply this
13 data as there are people in this room, probably more. For
14 instance, if I were to apply Ms. Carlock's new methodology
15 to the volumes and prices used by Ms. Carlock in her direct
16 testimony for the quantification of the alleged $4.6 million
17 of overcharge ($3.6 million Idaho jurisdiction) for real
18 time transactions, the $4.6 million benefit ($3.6 million
19 Idaho jurisdiction) to operating changes to a $16.4 million
20 detriment to operating. I'm certain that if I were to claim
21 this $16.4 million should be recovered by non-operating from
22 operating, someone could prepare a presentation of the data
23 that would counter that claim. This could be an endless
24 debate - all of which is irrelevant to this proceeding.
25 Q. Ms. Carlock asserts in her additional
testimony that "Using the Mid C index produces a transfer
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HOYD, ADDITIONAL-REB
Page 3 of 6
1 price that disadvantages customers", do you agree with this
2 assertion?
3 A. No. The Mid-C index continues to be
4 representative of the day ahead pricing in the Idaho Power
5 regional markets. Using the objective, liquid, published
6 market index most indicative of the Idaho Power regional
7 markets has always been the purpose of the transfer pricing
8 mechanism.
9 Q. Was the Mid-C index representative of the
10 average purchase or sale price in the non-operating
11 portfolio?
12 A. Depending on how you sort, segment, add,
13 subtract or average the non-operating data, the answer can
14 be yes or no, however, the intent of the transfer pricing
15 was never to achieve prices that were reflective of the non-
16 operating book of business. The purpose was just the
17 opposite. In an effort to ensure that risks being
18 undertaken by non-regulated trading activities were not
19 passed through to the ratepayers of the regulated utility,
20 the day ahead transfer pricing mechanism was intentionally
21 set up to use a third party source of market information
22 rather than passing on risks to ratepayers by using
23 transactions entered into by the trading operation.
24 Q. Please explain what Ms. Carlock has set forth
25 in her Exhibits Nos. 134 and 135.
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HOYD, ADDITIONAL-REB
Page 5 of 6
1 A. It appears in Exhibit 134 she has attempted
2 to compare the heavy load and light load day ahead transfer
3 price at the Mid-C index to the real-time average price
4 used to ensure the real-time price risk for the day ahead
5 transfer was appropriately accounted for as a non-operating
6 risk.
7 Q. Does it concern you that these prices are
8 different?
9 A. No. I would expect day-ahead prices to be
10 different than real-time prices.
11 Q. Does Ms. Carlock perform the same comparison
12 in Exhibit 135?
13 A. No. Although she appears to be comparing
14 day-ahead prices with real-time prices, she is again
15 comparing monthly averages against monthly averages for
16 what is a daily market.
17 Q. Ms. Carlock contends that there is an anomaly
18 in the day-ahead transfer pricing mechanism for the period
19 April 2000 through February 2001. Do you agree this
20 anomaly existed?
21 A. No. Idaho Power Company has applied the same
22 procedures for pricing the day-ahead transfer between
23 operating and non-operating since January 1999. In fact,
24 during the course of Staff's audit of the 1999-2000 PCA true
25 up, Ms. Carlock and other members of Staff spent several
hours with our accounting and trading group to make sure
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HOYD, ADDITIONAL-REB
Page 6 of 6
1 they had a full understanding of this process. Staff
2 indicated no concerns about the process at that time.
3 Q. Is it possible for the procedure used for
4 pricing day-ahead transfers at the Mid-C index to create a
5 mismatch?
6 A. The procedures used for creating the day
7 ahead transfer from January, 1999 through November, 2000
8 was the only way possible to ensure that a mismatch of the
9 day ahead Mid-C priced transactions and real-time priced
10 transactions did not occur given that all real-time
11 transactions were classified as operating. If real-time
12 transactions had been classified as non-operating, the
13 real-time priced offset in question would not have been
14 necessary. This is the primary change Idaho Power made in
15 December, 2000 that Ms. Carlock contends we should not have
16 made.
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HOYD, ADDITIONAL-REB
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1 (The following proceedings were had in
2 open hearing.)
3 COMMISSIONER KJELLANDER: Let's proceed, and
4 I believe that we will begin, let's see, why don't we begin
5 with the Deputy Attorney General representing the IPUC
6 Staff and that would get us going.
7 MS. NORDSTROM: Thank you.
8 COMMISSIONER KJELLANDER: Thank you.
9
10 CROSS-EXAMINATION
11
12 BY MS. NORDSTROM:
13 Q On page 2 and 3 of your rebuttal testimony --
14 A The original rebuttal testimony?
15 Q Correct.
16 COMMISSIONER KJELLANDER: And for purposes of
17 everyone, including the Commission, if you're going to ask
18 questions back and forth between the additional and the
19 original filed, if you could just specify that up front.
20 MS. NORDSTROM: Okay, thank you, I will do
21 that.
22 Q BY MS. NORDSTROM: On page 2 and 3 of your
23 rebuttal testimony previously filed this month, Ms. Hoyd,
24 you state that the Staff cost calculation of acquiring
25 energy to supply the system is incomplete because it did
574
CSB REPORTING HOYD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 not include other costs. Are these costs normally recorded
2 in the accounts included in the PCA calculation?
3 A These costs were not recorded in the accounts
4 used for the PCA calculation, just like the energy costs
5 were not recorded in those accounts.
6 Q And that's standard practice?
7 A Standard practice is to record the
8 non-operating costs and expenses in the non-operating
9 accounts.
10 Q But not in the PCA accounts?
11 A Correct.
12 Q For example, is it correct that transmission
13 expenses, including the $55 million referenced on page 3,
14 line 24 of your rebuttal testimony, is booked to Account
15 421 and is not an account that is flowed through the PCA?
16 A It's correct that the non-operating
17 transmission expense was not included in the PCA accounts.
18 Q If it isn't in the PCA calculation, wouldn't
19 it be accurate to exclude these costs when making a
20 comparison to the PCA power costs?
21 A I don't think any of the costs or revenues
22 included in the non-operating accounts should be compared
23 to the costs going through the PCA accounts.
24 Q Was the $55 million paid in transmission
25 expense by the non-operating business to counterparties?
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CSB REPORTING HOYD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 A Yes.
2 Q How much was paid to Idaho Power for
3 transmission?
4 A How much did Idaho Power pay Idaho Power for
5 transmission, is that the question?
6 Q How much did the non-operating system pay the
7 regulated operating system for transmission?
8 A We did not -- there was no dollar transfer
9 between non-operating business and operating business for
10 any transmission. I might add that there was calculations
11 made between the delivery unit and the marketing unit for
12 the cost of transmission in accordance with FERC
13 regulations.
14 Q You've indicated on page 5 and 6 of your
15 rebuttal testimony that Staff has chosen a market basket of
16 non-operating transactions that are not relevant because
17 they occur at different locations; is that correct?
18 A Yes.
19 Q Company workpapers on rebuttal reflect only
20 those transactions that are at the system border and are
21 deliverable. Isn't it correct that use of these
22 transactions at the system border would resolve the concern
23 with respect to location?
24 A Appropriate use of these transactions in
25 comparing an energy price in the Northwest against an
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CSB REPORTING HOYD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 energy price at the Mid-C index price would be an
2 appropriate use of the transactions. Those prices and
3 transactions as given to Staff do not reflect the cost of
4 the energy delivered to the system. I might clarify. It
5 does not reflect the cost of all of the energy delivered to
6 the Idaho Power system for non-operating and operating
7 uses.
8 Q So could you explain again why that doesn't
9 resolve the concern there?
10 A Well, I think in the additional rebuttal I
11 tried to resolve that or clarify that difference of
12 opinion. What I tried to do in the original rebuttal
13 testimony that I filed was to alleviate a concern that
14 Staff had brought up or that Ms. Carlock had brought up
15 that potentially the Mid-C index is no longer a reflective
16 market price for Idaho Power transactions, so in doing so,
17 I took some transactions as an example out of our
18 non-operating book of business that occurred in the
19 Northwest that had a delivery point on the Idaho Power
20 system to say the sales price at the Idaho Power system is
21 reflective of the sales price at the Mid-C index; the
22 purchase price is reflective of the purchase price.
23 I don't believe anywhere in my testimony I
24 said that those transactions could be used as an accurate
25 representation of the cost to supply the system with
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CSB REPORTING HOYD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 power. I guess I might further add that the delivery point
2 itself in the transactions that I included is an indication
3 of what the seller's obligation is to provide to the buyer,
4 obligation of seller to provide the buyer with energy at a
5 delivery point. There are many, many other transactions
6 where Idaho Power non-operating was required to purchase
7 power at a delivery point off of the Idaho Power system and
8 then purchase transmission to bring that power in to the
9 Idaho Power system. The purpose of my testimony was to say
10 the energy price at a location off of the Idaho Power
11 system is not reflective of an energy price in the
12 Northwest. It wasn't to say that we never did purchase
13 power off of the system and transmit it in.
14 Q Isn't it true that the Mid-C market price
15 index used for day-ahead transactions is actually an
16 average of all transactions within the respective load
17 periods?
18 A Mid-C index is yes, an average of heavy load
19 or light load day-ahead transactions occurring at Mid-C.
20 Q And isn't it true that neither the day-ahead
21 Mid-C index nor the Staff average compares hourly prices to
22 the hour the energy is used by Idaho Power?
23 A The Mid-C -- well, maybe I can clarify a
24 little bit what happens in a day-ahead market. The
25 day-ahead market itself does not transact for specific
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CSB REPORTING HOYD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 hours in the next day. You buy and sell a heavy load
2 period or you buy and sell a light load period, so the
3 Mid-C average index for day-ahead markets when it says it's
4 an average heavy load price or an average light load price
5 is the average price for all of the transactions relevant
6 to that block of time.
7 I don't know if I'm making myself clear or
8 not, but basically I guess the point is that day-ahead
9 transactions in the marketplace don't specify specific
10 hours. You buy and sell for the block of energy, the heavy
11 load block or the light load block.
12 Q So your contention that the Staff average
13 isn't appropriate because it doesn't compare to hours isn't
14 any different than using the Mid-C market index which
15 doesn't compare the hours, the appropriate hours used;
16 correct?
17 A Well, let me see if I can answer your
18 question as I understand you're asking it. The Mid-C index
19 is the market price for day-ahead transactions for the
20 heavy load block or the light load block of energy. What
21 I'm saying that I have concerns with in Ms. Carlock's
22 testimony is that in each day there is a heavy load price
23 and a light load price. There's heavy load volumes and
24 light load volumes and by taking an average of all of those
25 transactions in a month and saying that that's an average
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CSB REPORTING HOYD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 price and comparing that to all of the transactions that
2 occurred in the month where you've got volumes and prices
3 different on every day that that's an inaccurate
4 representation.
5 Q Okay. On page 6, line 3 you discuss credit
6 risks of counterparties and you state that all the
7 potential benefits associated with the risks of the
8 non-operating transactions are passed on to the utility
9 operation without the utility operation assuming any of the
10 risk, but if you referred to the Idaho Power/IDACORP Energy
11 contract, statement of services, item 9, which is Staff
12 Exhibit 117, I believe the Company has that as an exhibit,
13 also --
14 MR. RIPLEY: Mr. Chairman, again I'm going
15 to object. That contract was not in existence for purposes
16 of --
17 COMMISSIONER KJELLANDER: Could you get
18 closer to your microphone? I can barely hear you.
19 MR. RIPLEY: I'm sorry. I will have to
20 object because I believe that counsel is now referring to a
21 period of time that is in the future, not the period of
22 time in which the PCA in 7/11 was to be considered; i.e.,
23 the period ending February 28, 2001.
24 MS. NORDSTROM: Staff will withdraw the
25 question.
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CSB REPORTING HOYD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 COMMISSIONER KJELLANDER: Thank you. Please
2 proceed.
3 Q BY MS. NORDSTROM: In your rebuttal
4 testimony, you also discuss transfer pricing. Is the
5 transaction as shown in your Exhibit 30 for the transfers
6 from real-time to day-ahead a hedge that is currently in
7 place?
8 A Well, maybe I can clarify that or try and
9 clarify that again from the example given earlier. What
10 that is, is essentially when you actually strip it down to
11 its basics, it's a bookkeeping transfer to make sure that
12 the ability or that the desire of the utility to go into
13 real-time flat or balanced actually occurs for accounting
14 and PCA purposes. It is true that the utility has had a
15 practice and procedure in place for years and I think it's
16 actually fairly common in the industry to take -- to try
17 not to take the utility into real-time with an open
18 position and this is our way of accomplishing that between
19 op and non-op.
20 Q On what date was this transaction instituted?
21 A It has been -- the transaction between
22 operating and non-operating has been in place since January
23 of 1999. As I state in my additional rebuttal testimony,
24 because of the classification of real-time transactions
25 being operating, day-ahead transactions being
581
CSB REPORTING HOYD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 non-operating, this offset is required to ensure that the
2 real-time risk lands in the right bucket, essentially.
3 Q Do you agree that this was a term
4 transaction?
5 A No.
6 Q Why not?
7 A Because it happens every day, volumes change
8 every day. Some days the system is long, some days the
9 system is short. It's completely unpredictable.
10 Q So someone makes a decision every day to
11 reinstate this hedge?
12 A Somebody follows the operating procedures
13 every day to not take the system into real-time with
14 real-time risk.
15 Q So therefore, it's an ongoing transaction;
16 correct?
17 A It is a procedure every day that's been in
18 place since before we even had op and non-op to limit the
19 real-time risk of the operating system.
20 Q So why has the Company created an entire
21 accounting procedure for a daily transaction?
22 A We created a procedure that was necessary
23 once we began accounting for this difference between
24 operating and non-operating to make sure that the
25 operational practice and procedure was accounted for
582
CSB REPORTING HOYD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 correctly between the two books of business.
2 MS. NORDSTROM: May I have just a moment?
3 COMMISSIONER KJELLANDER: Yes.
4 (Pause in proceedings.)
5 Q BY MS. NORDSTROM: When the non-operating
6 system was created, did this transfer funds that were not
7 previously transferred?
8 A Can you please repeat the question?
9 Q The risk was on the non-operating book -- oh,
10 sorry. The risk was on the operating book prior to
11 shifting it to the non-operating book; correct?
12 A The real-time if the system prior to
13 operating and non-operating, if the traders were unable to
14 actually trade to a zero balanced position for the system,
15 the day-ahead, then, yes, the system would have had
16 real-time risk.
17 Q So in essence, by doing this, you shifted
18 risk from operating to non-operating; correct?
19 A Yes.
20 Q And who made that decision?
21 A As I say, it was a procedural, operational
22 procedure that was in place long before operating and
23 non-operating and I can't tell you who originally made the
24 decision. Probably a vice president of power supply along
25 the way.
583
CSB REPORTING HOYD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 Q Has it been discussed by the Risk Management
2 Committee?
3 A I can't answer that. I don't know and I
4 don't know that the Risk Management Committee would feel
5 they needed to discuss an operating procedure that had been
6 in place.
7 Q Even if it transfers risk?
8 A As I stated, I think that our executive
9 management had felt that that decision had been made long
10 before there ever was operating and non-operating.
11 Q You testified that the Company hedged
12 day-ahead against real-time. Do you agree with Dr. Peseau
13 that this hedge can create perverse incentives between the
14 affiliates or the operating and non-operating systems?
15 A No. I guess in answer to your question, I
16 don't agree that limiting the amount of real-time risk that
17 operating takes going into the real-time markets creates a
18 perverse incentive anywhere. I can't really speak to
19 Dr. Peseau's answer or even if that's specifically what he
20 was referring to.
21 Q So do you disagree with him or you just don't
22 know?
23 A I guess what I'm saying is I can't interpret
24 what Dr. Peseau was saying or what question his response
25 was to, so I can't comment on whether I agree or don't
584
CSB REPORTING HOYD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 agree with him. What I am saying is that I think that the
2 procedure of not taking the operating system into
3 real-time, long or short, creates any perverse incentive
4 between operating and non-operating.
5 Q Okay, in regards to your supplemental
6 testimony filed this morning, you have previously testified
7 that day-ahead transactions are classified as
8 non-operating; is that correct?
9 A Yes.
10 Q Do you have a copy of the Company rebuttal
11 workpapers with you?
12 A Somewhere.
13 Q Okay, could you please refer to the November
14 documents or do you think you can answer several questions
15 without using them?
16 A If you're going to ask me questions relating
17 to the documents, I probably should get them.
18 MR. RIPLEY: I guess I need just a little bit
19 more identification as to the documents counsel is
20 referring to. There were a myriad of workpapers.
21 MS. NORDSTROM: May I approach?
22 COMMISSIONER KJELLANDER: Yes.
23 (Ms. Nordstrom approached the witness.)
24 Q BY MS. NORDSTROM: Isn't it true that the
25 Company workpapers include the total day-ahead transactions
585
CSB REPORTING HOYD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 as indicated by the title on the detail pages of "Non-op
2 Sales-All" and "Non-op Purchases-All"?
3 MR. RIPLEY: Excuse me, Counsel, could I
4 approach my own witness and look at the documents with the
5 witness in aid of an objection?
6 COMMISSIONER KJELLANDER: Certainly.
7 (Mr. Ripley approached the witness.)
8 MR. RIPLEY: I'm sorry, I have no objection.
9 COMMISSIONER KJELLANDER: Please proceed.
10 THE WITNESS: Can you repeat your question,
11 please?
12 Q BY MS. NORDSTROM: Isn't it true that the
13 Company workpapers include the total day-ahead transactions
14 as indicated by the title on the detail pages of "Non-op
15 Sales-All" and "Non-op Purchases-All"?
16 A These workpapers should include all of the
17 non-op day-ahead purchases and sales.
18 Q Please explain, then, how your statement on
19 supplemental rebuttal page 2, line 6 -- actually line 10,
20 I'm sorry, "the summary of transactions listed indicate
21 that this is all of the day-ahead energy delivered into the
22 IPC system"?
23 A Well, this is not the data given to
24 Ms. Carlock that I was referring to in that sentence. I
25 also gave her information that narrowed down the
586
CSB REPORTING HOYD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 transactions from all of the transactions to the
2 transactions that had a delivery point at the IPC system
3 border and it's my belief that those are the workpapers
4 Ms. Carlock used for her analysis.
5 Q Do these narrowed numbers roll forward into
6 the -- from the totals?
7 A If you want to look at these workpapers, you
8 can see that it has an indication in one of the columns of
9 whether or not it was a system intertie point or not and
10 then the additional workpapers that Ms. Carlock drew her
11 summaries from was basically a subset of this that included
12 just the system-type [inaudible].
13 MS. NORDSTROM: Thank you. I have no further
14 questions, unless the Commission would allow me a moment to
15 confer with my client.
16 COMMISSIONER KJELLANDER: Given the fact that
17 it's only 9:30, yes.
18 MS. NORDSTROM: Thank you.
19 (Pause in proceedings.)
20 MS. NORDSTROM: Staff really doesn't have any
21 further questions.
22 COMMISSIONER KJELLANDER: Let's move to
23 Mr. Richardson.
24 MR. RICHARDSON: No questions, Mr. Chairman.
25 COMMISSIONER KJELLANDER: Are there questions
587
CSB REPORTING HOYD (X-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 from the Commission?
2 Commissioner Smith.
3
4 EXAMINATION
5
6 BY COMMISSIONER SMITH:
7 Q In one of your responses to Ms. Nordstrom, I
8 got confused. Maybe I just misunderstood what you said.
9 It was something like the transfer system was in place
10 before there was non-op and op.
11 A That the transfer --
12 Q -- system was in place.
13 A Oh, maybe I just wasn't clear on that.
14 Before there was op and non-op, the procedure of trading so
15 that the system didn't go into real-time, long or short,
16 was in place, but there wasn't any transactions that had to
17 occur because of that.
18 Q So this procedure seems quite mechanical.
19 A It is quite mechanical.
20 Q So there's no duty on the part of the people
21 who are trading in day-ahead so you're not in the real-time
22 to minimize the costs to the utility; correct?
23 A I don't think that that is a correct
24 interpretation of what was going on. What's going on with
25 that procedure is a process of trying to minimize the risk
588
CSB REPORTING HOYD (Com-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 of the utility system.
2 Q Right.
3 A We don't want the traders to try and
4 determine whether or not they think real-time prices might
5 be higher or lower than day-ahead prices. We just don't
6 want them to take the risk of that kind of volatility that
7 you see in real-time.
8 Q So they're not concerned with minimizing
9 costs?
10 A They are concerned with minimizing costs, but
11 they're also concerned with minimizing risk.
12 Q What you just said is if they were seeing
13 that they were going to be short the next day, they would
14 buy at whatever price.
15 A They would buy it in day-ahead.
16 Q Yes, whatever the price.
17 A Well, at that point we do have an obligation
18 to serve. We have to have the power to meet our obligation
19 and so then their choice at that point is just to buy
20 day-ahead or to buy in real-time.
21 Q So the duty to minimize the power supply cost
22 to the utility operations doesn't rest here.
23 A Well, I guess I'm not quite following. I
24 think that the duty to try and minimize the cost and
25 minimize the risk and manage the reliability of the system
589
CSB REPORTING HOYD (Com-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 and to balance all three of those potentially competing
2 objectives rests with the executive management of Idaho
3 Power all the way down through the group managing the
4 system on a day-to-day basis.
5 COMMISSIONER SMITH: Thank you.
6 COMMISSIONER KJELLANDER: We'll move now to
7 redirect.
8 MR. RIPLEY: We have no redirect.
9 COMMISSIONER KJELLANDER: Thank you.
10 Ms. Hoyd, you're excused.
11 (The witness left the stand.)
12 COMMISSIONER KJELLANDER: Would you like to
13 call your next witness on rebuttal?
14 MR. RIPLEY: We call Mr. Gale.
15
16 JOHN R. GALE,
17 produced as a rebuttal witness at the instance of the Idaho
18 Power Company, having been previously duly sworn, resumed
19 the stand and was further examined and testified as
20 follows:
21
22 DIRECT EXAMINATION
23
24 BY MR. RIPLEY:
25 Q Would you state your name for the record,
590
CSB REPORTING GALE (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 please?
2 A John R. Gale.
3 Q And are you the same Mr. Gale that has
4 presented direct testimony in this proceeding?
5 A Yes, I am.
6 Q Did you have cause to be prepared for this
7 proceeding certain rebuttal testimony consisting of seven
8 pages?
9 A Yes.
10 Q And included in that rebuttal testimony is
11 the identification and the description of Exhibit 29?
12 A That's right.
13 Q And if I asked you the questions that are set
14 forth in your direct rebuttal, would your answers be the
15 same today?
16 A Yes, they would.
17 Q Do you have any changes or corrections to
18 that testimony?
19 A Not to give you a heart attack, but I'd like
20 to correct a grammar, if I may. On a reread on page 2, the
21 question on line 4 is an incomplete sentence. It needs to
22 be one sentence instead of two, a comma after "instance."
23 Just a nit, but it bugged me when I read it again. That's
24 all.
25 Q All right, and then you have also caused to
591
CSB REPORTING GALE (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 be prepared in this proceeding certain additional rebuttal?
2 A Yes, I did.
3 Q And does that consist of two pages?
4 A Two whole pages.
5 Q And if I asked you the questions that are set
6 forth on your additional rebuttal, would your answers be
7 the same today?
8 A Yes, they would.
9 MR. RIPLEY: As a housekeeping measure,
10 Mr. Commissioner, what we did is we entitled Mr. Gale's
11 testimony in the lower right-hand corner, and I neglected
12 to say this for Ms. Hoyd, it's Gale direct rebuttal and
13 then the additional rebuttal we entitled Gale additional
14 rebuttal and then we have new pages, page 1 of 2 and page 2
15 of 2.
16 Q BY MR. RIPLEY: Now, as a final housekeeping
17 measure, yesterday or the day before, time blends here, you
18 were asked by Commissioner Hansen if you had any indication
19 as to the hedging that Idaho Power Company had performed
20 during the period March 1, 2000 through April 28, 2001. Do
21 you recall that?
22 A Yes.
23 Q And have you gone back through the Company's
24 responses to various information requests and found the
25 document that you were referring to?
592
CSB REPORTING GALE (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 A Yes.
2 COMMISSIONER KJELLANDER: You may approach
3 the witness or us.
4 (Mr. Ripley distributing documents.)
5 Q BY MR. RIPLEY: And could you describe --
6 well, let me first ask if this can be marked as 31 for
7 identification. It's a one-page exhibit entitled "Hedging
8 Benefit/Cost."
9 COMMISSIONER KJELLANDER: Without objection.
10 (Idaho Power Company Exhibit No. 31 was
11 marked for identification.)
12 Q BY MR. RIPLEY: Without going into detail,
13 Mr. Gale, could you briefly describe what Exhibit 31 is?
14 A It is a summary page of a response made to a
15 Staff audit request. It was audit request 16, and it
16 summarizes actually the results of the hedges in the PCA
17 year and going forward for a few months as well as the
18 transactions by month, both those that ended up in the
19 money and those that ended up outside the money for the PCA
20 year. The particular point or the reason that I wanted to
21 bring this up is this is in response to Commissioner
22 Hansen's questions on hedges during the PCA year. This
23 document summarizes those transactions.
24 MR. RIPLEY: All right. With that, we would
25 request that Mr. Gale's rebuttal testimony and his
593
CSB REPORTING GALE (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 direct -- and his additional rebuttal testimony be spread
2 upon the record as if read, his exhibit be identified as
3 indicated in his prepared testimony and would tender
4 Mr. Gale for cross-examination.
5 COMMISSIONER KJELLANDER: Without objection,
6 we'll spread the testimony and admit the exhibits.
7 MS. NORDSTROM: Staff doesn't have an
8 objection to this exhibit; however, we will note that it
9 does extend or cover periods outside of this proceeding,
10 the PCA year in question.
11 COMMISSIONER KJELLANDER: And we'll move
12 forward and to the extent that any of that becomes an issue
13 in the course of questioning, then we certainly expect to
14 hear from you in that regard. All right, then there is no
15 objection, we will spread the testimony and admit the
16 exhibits.
17 (Idaho Power Company Exhibit Nos. 29 and
18 31 were admitted into evidence.)
19 (The following prefiled rebuttal and
20 additional rebuttal testimony of Mr. John Gale is spread
21 upon the record.)
22
23
24
25
594
CSB REPORTING GALE (Di-Reb)
Wilder, Idaho 83676 Idaho Power Company
1 Q. Please state your name and business address.
2 A. My name is John R. Gale and my business
3 address is 1221 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 Vice
7 President of Regulatory Affairs.
8 Q. Have you previously submitted prefiled direct
9 testimony in this proceeding?
10 A. Yes.
11 Q. Mr. Lord contends on page 4, of his prefiled
12 direct testimony, beginning on line 5, "Over time the PCA
13 guarantees the customer will pay average cost of market
14 prices." Is this a true statement?
15 A. No. The PCA was not designed to set customer
16 rates at passed-through market purchase prices -rather
17 rates reflect system fuel, purchases including Qualifying
18 Facilities, and also offsetting system sales. At best, one
19 might say that over enough time, customers pay the average
20 net power supply costs. However, the sharing feature and
21 regulatory treatment may qualify this statement as well.
22 Q. On page 18, line 3 of Mr. Lord's direct
23 testimony, he states that he is unable to determine whether
24 IES charges a brokerage fee for arranging transactions for
25 Idaho Power. Is there a brokerage fee?
595
GALE, DI-REB 1
Idaho Power Company
1 A. IDACORP Energy did not charge Idaho Power a
2 brokerage fee for the time period covered by this case,
3 April 1, 2000 to February 28, 2001.
4 Q. Mr. Lord indicates his support of Staff's
5 "lower of cost or market" remedy in this instance, yet he
6 states that is not a sustainable situation. Do you agree
7 with his conclusion?
8 A. I fully agree that it is an unsustainable
9 relationship for exactly the reason Mr. Lord states on page
10 35, line 11. The Staff's pricing proposal allocates all
11 the risk to IDACORP Energy and all potential reward to
12 Idaho Power. I do not believe any trading company would be
13 interested in such an arrangement.
14 Q. Ms. Carlock contends that the Power Cost
15 Adjustment may be modified extensively as part of the
16 annual ratemaking process. What is your view?
17 A. I believe that the annual PCA review is a
18 validation of the power supply expenditures made on behalf
19 of the system and its customers. It may also be the
20 appropriate time to initiate modifications to the PCA
21 mechanism on a prospective basis, not retroactively for
22 either the economic benefit of the utility or its customers.
23 A good example of how PCA modifications have been
24 accomplished in the past can be found in Case IPC-E-98-13.
25 In this case the Company requested authority to include
596
GALE, DI-REB 2
Idaho Power Company
1 increased purchases of Qualifying Facilities in the PCA
2 projection method. In this instance the Commission ruled
3 that the increased purchases would be reflected in
4 prospective PCA projections. I believe any changes to the
5 methodology for pricing the systems purchases should
6 likewise be made on a prospective basis.
7 Q. Do you believe transfer pricing is set until
8 changed by the Commission prospectively?
9 A. Yes. If a standard transfer price mechanism
10 is not in place, then there is only uncertainty concerning
11 market transactions and their underlying economics.
12 Q. Why then was it appropriate for the Company
13 to modify its transfer pricing policy based upon Commission
14 approval of the IES/IPC Agreement?
15 A. I believe it was appropriate to use the new
16 transfer pricing as soon as the Commission approved the
17 arrangement (Case No. IPC-E-00-13) regardless if the whole
18 Agreement was operative yet or not. Many energy
19 transactions were being conducted (and continue to be
20 conducted) in a very volatile environment. Standard
21 reporting for these transactions was and is required.
22 Transactions between operating and non-operating books have
23 direct ratemaking impacts regardless of the Agreement and
24 separation of the two entities. To not modify transfer
25 pricing at the time of Commission approval is the more
597
GALE, DI-REB 3
Idaho Power Company
1 difficult position to defend because it is neither fair nor
2 reasonable.
3 Q. Which transfer prices were changed based upon
4 IPUC approval of the IDACORP Energy Services/Idaho Power
5 Company Agreement?
6 A. Only the real-time transfer prices were
7 changed as a result of the Commission's approval of the
8 IES/IPC Agreement.
9 Q. How much of the $51 million in "repricing"
10 adjustments represent purchases made in real-time markets?
11 A. According to Ms. Carlock, only $4,666,381.95,
12 on a system basis, is related to the repricing of real-time
13 transactions. The Idaho jurisdictional portion of this is
14 approximately $3.6 million. That means $3.6 million, or
15 7%, of the $51 million of Staff's repricing adjustments is
16 related to the real-time transfer pricing change.
17 Q. Is the remaining $47 million related to
18 repricing of day-ahead transactions?
19 A. That is my understanding.
20 Q. How are day-ahead prices obtained?
21 A. Using the Mid-Columbia index (Mid-C) or Palo
22 Verde index (PV), whichever is the relevant market for the
23 day.
24 Q. How long has the Company been using Mid-C and
25 PV for day-ahead market transfer pricing?
598
GALE, DI-REB 4
Idaho Power Company
1 A. Since January of 1999 when the Company
2 implemented the new accounting standards described
3 extensively in Ms. Hoyd's and Mr. Said's direct testimony
4 in this proceeding.
5 Q. And the day-ahead transfer pricing was not
6 changed as a result of the Agreement?
7 A. No, it was not. The day-ahead transfer
8 pricing had been used for almost two years by the time the
9 Agreement had been approved by the Commission. This year
10 was the third time this pricing arrangement had appeared in
11 the annual Power Cost Adjustment audit and rate change.
12 Q. Staff continues to take issue with what has
13 been characterized as the "November transaction" that Staff
14 has valued at $10,288,386 because the "Rationale for a
15 change of vote has not been provided" (Ms. Carlock's
16 testimony on page 29 beginning on line 14). What is your
17 response?
18 A. The Company has maintained throughout that
19 the "November transaction" is a record keeping issue and not
20 one of execution. Based upon a hindsight review it can be
21 argued that, had the transaction occurred, expenses would
22 have been less. However, if one views the circumstances
23 surrounding the transaction in the context of when it
24 actually failed to occur, the "slam-dunk" conclusion is not
25 so obvious. To put the time frame into perspective, I had
599
GALE, DI-REB 5
Idaho Power Company
1 Exhibit 29 prepared. Exhibit 29 displays historical
2 information similar to exhibits of Mr. Simard and Dr.
3 Peseau. The forward price information used in Exhibit 29
4 reflects the price quotes given to one of Idaho Power
5 Company's special contract customers throughout the
6 relevant time period. Staff has received this information
7 through their Audit Request No. 47.
8 Exhibit 29 is a two-page exhibit. Page one
9 shows the prices quoted throughout the year 2000 for a one-
10 month, firm energy product for January 2001. It also shows
11 the prices quoted for an energy product that would extend
12 through December 2001. Page two reflects the previous
13 year's prices for the January 2000 energy product. The
14 Risk Management Committee meeting date is designated on the
15 chart. Given the information known at the time of the
16 meeting, it is beyond any reasonable expectation for
17 management to have anticipated what was going to happen
18 next. The prices already were high compared to historical
19 amounts and, at the time, a forward buy appeared to only
20 lock-in the high price. Additionally, the system was, at
21 that time, already long for the year and an additional
22 purchase would increase the overall system length.
23 Q. If the Commission determines that the $59
24 million deferred costs, or any portion thereof, should be
25 included in Idaho retail rates, what is the appropriate
600
GALE, DI-REB 6
Idaho Power Company
1 carrying charge to apply to that amount?
2 A. The appropriate rate is the applicable
3 interest rate used for the standard PCA deferral balance,
4 currently six percent, calculated from March 1, 2001 to the
5 time new rates are implemented.
6 Q. Does that conclude your prefiled rebuttal
7 testimony?
8 A. Yes.
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
601
GALE, DI-REB 7
Idaho Power Company
1 Q. Did you review the additional direct
2 testimony prepared by Staff witness Carlock?
3 A. Yes.
4 Q. Please comment on her statement. "This
5 comparison shows the Staff's day ahead system adjustment of
6 $61.5 million or $47 million to Idaho customers based upon
7 all transactions is not excessive."
8 A. For clarification, the $61.5 million is the
9 system and the $47 million is the Idaho jurisdictional
10 amount. As Ms. Hoyd discusses in her rebuttal testimony,
11 the justification for Ms. Carlock's statement is yet another
12 staff calculation that compares what she represents to be a
13 cost summary to market and then determines the market is
14 inappropriate. The data can be summarized in a variety of
15 ways. The Staff has presented a number of calculations
16 attempting to make the case that the Mid-C transfer price
17 was inappropriate for "this PCA period". These
18 calculations themselves underscore the need to rely on the
19 best market price available and not a number of
20 recalculations of the same data over and over again.
21 Q. Ms. Carlock states that her most recent
22 comparison is the most appropriate comparison to make for
23 PCA purposes because third party purchases may be sales to
24 Idaho Power from IE. Do you agree?
25 A. No I do not agree with what I understand her
statement to mean. For purposes of this answer, I will use
602
GALE-ADDITIONAL-REB
Page 1 of 2
1 her term of "IE" for the non-operating trading operation and
2 "Idaho Power" for the system. I understand her statement to
3 mean that because IE (non-operating) may have third party
4 purchases in its supply portfolio; it should transfer energy
5 to Idaho Power (operating) at its purchase cost rather than
6 the Mid-C day-ahead market price. If my understanding of
7 her conclusion is correct, then I believe her conclusion is
8 erroneous for two reasons. First, from IE's perspective, IE
9 could sell to other parties instead of Idaho Power and
10 receive the market price. Secondly if Idaho Power were
11 buying day-ahead energy from some other party, it would be
12 paying the market price. Even without the arrangement
13 between the operating and non-operating, both ends of the
14 transaction would be seeing and paying market, not cost.
15 Q. What is your conclusion?
16 A. The more the numbers are calculated and
17 recalculated; the more I see the need to rely on an
18 independent and discoverable market index for transfer
19 pricing purposes. The Mid-C is the most representative
20 price for Idaho Power day-ahead transactions. It has been
21 acceptable through two PCA adjustments and seems to be
22 acceptable for use in future PCA proceedings. I advocate
23 its use in the present proceeding because it is not only
24 what I believe to be the authorized transfer price, but
25 also the appropriate transfer price.
603
GALE-ADDITIONAL-REB
Page 2 of 2
1 (The following proceedings were had in
2 open hearing.)
3 COMMISSIONER KJELLANDER: And we will now
4 move forward with cross on the Deputy Attorney General
5 representing Staff, so Ms. Nordstrom.
6 MS. NORDSTROM: If the Commission would
7 indulge the Staff, we'd like to have about 15 minutes to
8 prepare for this in light of the new testimony filed by
9 Ms. Hoyd and Mr. Gale this morning. We had less than an
10 hour. It would be nice to have a couple more minutes.
11 COMMISSIONER KJELLANDER: Certainly. We'll
12 go ahead and go off the record and it's our intent, then,
13 to come back right around 10:00 o'clock.
14 MS. NORDSTROM: Thank you.
15 (Recess.)
16 COMMISSIONER KJELLANDER: We'll be back on
17 the record and I believe when we left we had already spread
18 the testimony and exhibits for the rebuttal testimony on
19 the record and we are ready now for cross-examination from
20 Ms. Nordstrom.
21 MS. NORDSTROM: Thank you.
22
23
24
25
604
CSB REPORTING GALE
Wilder, Idaho 83676 Idaho Power Company
1 CROSS-EXAMINATION
2
3 BY MS. NORDSTROM:
4 Q Referring to your previously filed rebuttal
5 or originally filed, on page 2, lines 1 through 3, is it
6 correct that a brokerage fee was not charged during this
7 PCA period?
8 A Yes.
9 Q Is there a possibility that this will change?
10 A No.
11 Q On Tuesday you stated that contract
12 negotiations were ongoing with IE to determine the value of
13 benefits associated with IE's use of regulated assets. Did
14 any of those benefits exist within the 2000-2001 PCA
15 period?
16 A I believe there were benefits that existed
17 during the PCA period.
18 Q Idaho Power has put forward the proposition
19 that the Company and Staff and customers should work
20 together to create risk management policies and
21 procedures. Did Idaho Power have policies and procedures
22 in place to control speculative trading risks during the
23 last PCA year?
24 A I'm not sure if I can adequately answer Idaho
25 Power's policies in the past year from a risk management
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1 perspective.
2 Q In regards to the testimony you filed this
3 morning, on the second page on line 8 it reads, "First,
4 from IE's perspective, IE could sell to other parties
5 instead of Idaho Power and receive the market price." This
6 implies that IE believes its relationship with Idaho Power
7 is the same as IE's relationship with any other market
8 participant. As Idaho Power's representative and in light
9 of the IDACORP Energy and Idaho Power Company service
10 contract and their relationship, do you feel this position
11 is appropriate?
12 A Well, the part of my testimony you're
13 referring to, what I'm speaking to, and I'm using the terms
14 that Ms. Carlock used, but what I'm speaking to is the
15 economics of that transaction and how it relates to op and
16 non-op from each entity's perspective which is not the same
17 as your question. If you would like to reask your
18 question, I'd be happy to answer that, but that wasn't the
19 context of the testimony.
20 Q Well, I guess more fundamentally, do you
21 believe that IDACORP Energy has a special relationship or
22 responsibility to Idaho Power Company?
23 A In what time frame are you referring to?
24 Q Within the PCA year.
25 A Okay, within the PCA year, we had Idaho Power
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1 non-op and Idaho Power op. We did not have IDACORP Energy.
2 Q Okay; so in the PCA year, did the
3 non-operating system have any kind of special
4 responsibility or relationship with the operating system?
5 A Yes.
6 Q What is it?
7 A Well, the non-op during the PCA year was
8 tasked with balancing the system, loads and resources, and
9 in the different markets, both in real-time and day-ahead
10 and term, when approved by the RMC, yes.
11 Q Was there any special relationship between
12 the operating system and the non-operating system in
13 regards to cost?
14 A We're talking about Idaho Power Company and
15 Idaho Power Company. Any cost transfers between Idaho
16 Power Company and Idaho Power Company is what I would say
17 is house money because those cost transfers have no way of
18 making their way into ratemaking.
19 Q So is this a method of allocation for cost?
20 A Is what a method of allocation for cost? I'm
21 sorry, is what a method?
22 Q The transfer pricing.
23 A Transfer pricing is a method of allocating or
24 assigning energy prices, allocating costs, if you will.
25 Q Do you believe that Idaho Power Company has a
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1 duty to acquire energy supply at lowest cost?
2 A I believe that Idaho Power Company has the
3 same three objectives to fulfill that Ms. Hoyd mentioned
4 just moments ago. It has to manage the system in respect
5 to cost, in respect to reliability and in respect to risk,
6 so it's a three-legged stool.
7 Q Do you believe that allowing the
8 non-operating system discretion to transact on behalf of
9 Idaho Power Company for current and prompt month without
10 Risk Management Committee review will assure Idaho Power
11 Company the lowest cost?
12 A The Risk Management Committee has after the
13 fact review of even those transactions. As a practical
14 matter, the Risk Management Committee cannot run the system
15 in day-ahead and real-time. It can only manage the
16 relationship with non-op and in the future with IE.
17 MS. NORDSTROM: One moment, please.
18 (Pause in proceedings.)
19 MS. NORDSTROM: Staff has no other
20 questions.
21 COMMISSIONER KJELLANDER: We'll move to
22 Mr. Richardson, but he's not at his seat, so we will go to
23 the Commissioners to see if there are any questions.
24 Commissioner Smith.
25 COMMISSIONER SMITH: Thank you.
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1 EXAMINATION
2
3 BY COMMISSIONER SMITH:
4 Q Mr. Gale, the Company has repeatedly pointed
5 out that the procedure that was used has been in place
6 since January of '99; is that correct?
7 A If I may make a distinction, the Mid-C part
8 of it, the day-ahead part of it, has been used since
9 January of 1999. That's the bulk of the dollars.
10 Q I guess my question is -- and that seemed to
11 be working well when there was a fairly narrow band within
12 which the prices fluctuated. Did anybody look at what was
13 happening when the prices started fluctuating within a much
14 larger band?
15 A In what time frame?
16 Q Well, I think the spikes started last spring,
17 May, June of 2000.
18 A And are you talking about as an alternative
19 to Mid-C or buying differently?
20 Q No, I'm looking at did anybody say shall we
21 look at our transfer pricing mechanism using Mid-C to see
22 what's coming out as results based on these kinds of
23 fluctuations in market price which we have never seen
24 before?
25 A No one to my knowledge challenged the
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1 validity of Mid-C during the year.
2 Q That's not what I'm asking. I'm asking if
3 anybody looked to see what the results were going to be by
4 continuing the same procedure in the face of these
5 radically different prices?
6 A And I am attempting to be as responsive as I
7 can. The impact of the forward prices were looked at as
8 part of the operating plan in the RMC. The forward price
9 curve, to the extent those prices were reflected going
10 through the PCA year and beyond, that impact was looked
11 at. Keep asking.
12 Q I don't know, maybe I didn't ask it
13 correctly. I guess what I'm asking is during the PCA year,
14 did anybody look to see what the results were going to be
15 by using the Mid-C for this transfer price method?
16 A As an impact to the customers?
17 Q Yeah, as an input into the PCA.
18 A Okay, the Risk Management Committee looked at
19 a forward look through the PCA and through the ongoing
20 months on what the market prices would have on the
21 customers. We did not say the Mid-C is broke. We view the
22 Mid-C as the market.
23 Q But did you look at this transfer procedure
24 to see exactly what it is that the Staff is arguing about,
25 that the procedure itself was no longer reasonable given
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1 these drastically different prices? Did anybody look to
2 see that this issue would come up, that this would be an
3 issue or was it just assumed that because it's been used
4 since January of '99 we don't need to look at that because
5 whatever it is we'll pass it through?
6 A No, we never viewed anything as we'll pass it
7 through, ever viewed anything as we'll pass it through.
8 The Company has a huge stake in every decision that is
9 made, more of a stake now than we ever had, so I'd like to
10 beat that one down. We don't view anything as we can pass
11 it through. Now, we did not challenge Mid-C as a price and
12 ultimately I don't believe Staff is challenging Mid-C as a
13 price. I think they are thinking we should have purchased
14 differently.
15 Q Or transferred differently.
16 A I believe purchased differently.
17 Q Well, whichever, I guess what I want to know
18 is did at any time during the PCA year somebody in the
19 Company say we ought to look at our procedure and what it's
20 resulting in now compared to what it resulted in in our
21 prior PCA years and see if it's still working and it's
22 still yielding a result that appears reasonable, did
23 anybody do that?
24 A We reviewed our purchase patterns, how we buy
25 from the market on a continual basis. We did not review
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1 the transfer prices.
2 Q Whose responsibility would it have been to do
3 that?
4 A I'm not sure where in management, potentially
5 RMC, potentially with me. The transfer prices we viewed as
6 the best transfer prices available. There was not a hint
7 that there's something wrong with the transfer prices and
8 so it was not on the radar screen.
9 COMMISSIONER SMITH: Well, and I guess I
10 would submit there was no hint because no one looked.
11 Thank you, Mr. Chairman.
12 COMMISSIONER KJELLANDER: Are there any other
13 questions from the Commission?
14 Commissioner Hansen.
15
16 EXAMINATION
17
18 BY COMMISSIONER HANSEN:
19 Q Well, Mr. Gale, probably this is along the
20 same lines as Commissioner Smith, but I guess that's the
21 question I have. I go back to February and at that time I
22 was asked to make a presentation to some legislators on the
23 PCA and how it interacted with the affiliate and the
24 regulated side, and I guess at that time I asked Idaho
25 Power people because I wanted to be assured because they
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1 had a concern at that time because of information that had
2 been put out publicly about the profits that were being
3 made by the nonregulated side, a concern that the regulated
4 people were being hit heavy and the benefits were going to
5 the non-regulated side, and I guess at that time, as I
6 recall, when I asked management is there anything happening
7 there that the regulated side is getting hit with the
8 expenses and the nonregulated is benefiting from the
9 profits and I recall I was told no, there is nothing, and
10 yet, I think if I'm on the same page as Commissioner Smith,
11 didn't anyone at that time look at it and realize what was
12 happening, that it wasn't really -- that it was
13 questionable the way the pricing was being conducted?
14 A My answer to both of you is that we transfer
15 prices at the best market price available. My answer to
16 you today is there was no profiting by the unregulated
17 piece of the Company at the expense of the regulated
18 piece. I say that for this reason: It is the same market
19 volatility and the same craziness in the prices that caused
20 the expense to the utility that also caused and provided
21 the opportunity for trading.
22 If Idaho Power had transacted its business
23 and there was no non-op and they were buying in the
24 markets, they would have bought at the same price as we're
25 transferring at. If IE was a separate trading operation
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1 and was selling into the market, it would obtain the same
2 prices that it sold to Idaho Power at. That's why I say
3 from both ends of the transaction what you see in our
4 representation of the cost would have been the same
5 representation if we'd had two separate entities.
6 Q Then what was the advantage of having the
7 nonregulated affiliate make the purchase? Why wouldn't it
8 have been just -- wouldn't they have been just as well off
9 to have Idaho Power make those purchases on the market
10 rather than going through IES?
11 A And I would say to you when buying in the
12 short-term markets, whether Idaho Power had done it
13 exclusively and there was no non-op or if they had bought
14 through the non-op, it's the same result.
15 Q So would you say the money that they paid,
16 the 300,000 a month in November and December, was really
17 for nil? They might as well have thrown it out the window,
18 they didn't get anything for it?
19 A No, sir, but first of all, they didn't pay
20 then. There was no relationship for money that was going
21 back and forth because the agreement wasn't in place, but
22 the advantage that the trading floor brings is an advantage
23 of economic scale, less cost come base ratemaking time and
24 that's something when we get into the other case, you will
25 see that is recognized and flowed through, and they also
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1 get some expertise in deciding what to do with term
2 transactions, but the shorter-term markets, the real-time
3 and day-ahead, that's going to operate pretty much exactly
4 the same if you have a non-op relationship or no
5 relationship.
6 COMMISSIONER KJELLANDER: We'll now move to
7 redirect.
8
9 REDIRECT EXAMINATION
10
11 BY MR. RIPLEY:
12 Q Mr. Gale, in looking at the power cost
13 adjustment, if the cost of power Idaho Power Company has to
14 acquire on the open market goes up because the market price
15 is going up, I assume that the amount that is being
16 deferred in the power cost adjustment in turn will go up;
17 is that true?
18 A That's true.
19 Q Now, when you're looking, then, at the time
20 period we're talking about, was the Company aware that
21 costs that it was deferring were increasing dramatically as
22 a result of market prices?
23 A Costs were going up because market prices
24 were up and we had a bad water year and we had to be in
25 that market on the buy side.
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1 Q Now, part of your duties, as I understand it,
2 is for you to look at the power cost adjustment
3 procedures.
4 A That's right.
5 Q Do you believe that the power cost adjustment
6 procedures were reflecting exactly what was going on and
7 that is the market price of power was increasing?
8 A Yes.
9 Q Was there anything wrong with the power cost
10 adjustment as to that procedure?
11 A Well, there's nothing wrong with the power
12 cost adjustment.
13 Q What the Company could have done, I assume,
14 is it could have gone out and bought power differently, it
15 could have purchased power differently than relying upon
16 the market price of power on a day-ahead; is that what you
17 were conferring with Ms. Smith about?
18 A The Company bought market day-ahead, it also
19 bought term, as I was trying to show in my exhibit, but I
20 believe fundamentally it's the issue not with the transfer
21 prices but with the way we bought power.
22 Q Now, if for some reason in December prices
23 would have dropped dramatically and the Company was buying
24 on day-ahead, then I assume the amount of the deferral in
25 the power cost adjustment would in turn drop dramatically?
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Wilder, Idaho 83676 Idaho Power Company
1 A That's a correct assumption.
2 Q So then we get back again to the fact what
3 we're talking about is should the Company have purchased
4 differently, not that the power cost adjustment was wrong?
5 A That's my view.
6 MR. RIPLEY: That's all the redirect I have.
7 COMMISSIONER KJELLANDER: Thank you. You're
8 excused.
9 (The witness left the stand.)
10 COMMISSIONER KJELLANDER: Does that conclude
11 your rebuttal?
12 MR. RIPLEY: Yes, sir, it does.
13 COMMISSIONER KJELLANDER: Are there any other
14 matters that need to come before the Commission?
15 MS. NORDSTROM: I have one. It's become
16 apparent based on the extensive cross-examination that's
17 been presented as well as the testimony and the exhibits
18 that the Commission is going to have a lot to review in
19 making this decision. In addition, the transcripts will
20 take traditionally 14 days to be prepared. It's my
21 understanding the Commission has suspended this particular
22 application through September 28th.
23 The Commission may want to consider taking
24 additional time to review all this information, to
25 deliberate and prepare an order that reflects your views.
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1 That may take more than two weeks, so if you feel you need
2 additional time, I'd ask that you consider that.
3 COMMISSIONER KJELLANDER: Any other matters
4 that need to come before the Commission?
5 MR. RIPLEY: Just a housekeeping measure.
6 I'm uncertain as to whether or not the exhibits that have
7 been offered have all been admitted.
8 COMMISSIONER KJELLANDER: Before I closed out
9 today, I was just going to go ahead and throw out a blanket
10 on just that and thank you for bringing that to my
11 attention, and for the record, then, all of the exhibits
12 that have been presented here today will be officially
13 admitted into the record.
14 (All exhibits previously marked for
15 identification were admitted into evidence.)
16 COMMISSIONER KJELLANDER: And we look forward
17 to an opportunity to once the transcript arrives begin our
18 deliberations and at that point we will, I think, be able
19 to take into consideration the concern raised by
20 Ms. Nordstrom based on where we're at and what we see at
21 that given point in time and if there is any adjustment
22 from the September 28th date, which I think has been
23 previously identified as a target, we would certainly make
24 all the parties aware of how we intend to proceed if there
25 is any delay with regard to that date, so with that, then,
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1 we would see this particular piece of the proceeding being
2 concluded and we thank everyone for their participation,
3 and just as a procedural note, it is the intent to begin
4 with the 16 case and once we officially adjourn and go off
5 the record, I think there should be some discussion as far
6 as the actual start time for that and so with that, then,
7 we are adjourned.
8 (The Hearing adjourned at 10:30 a.m.)
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1 AUTHENTICATION
2
3
4 This is to certify that the foregoing
5 proceedings held in the matter of the Idaho Power Company
6 application for a refundable emergency energy charge for
7 the recovery of extraordinary power supply expenses, and in
8 the matter of the Idaho Power Company application for
9 authority to implement a power cost adjustment (PCA) rate
10 for electric service from May 1, 2001 through May 15, 2002,
11 commencing at 9:30 a.m., on Tuesday, August 28 and
12 continuing through Thursday, August 30, 2001, at the
13 Commission Hearing Room, 472 West Washington, Boise, Idaho,
14 is a true and correct transcript of said proceedings and
15 the original thereof for the file of the Commission.
16 Accuracy of all prefiled testimony as
17 originally submitted to the Reporter and incorporated
18 herein at the direction of the Commission is the sole
19 responsibility of the submitting parties.
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23 CONSTANCE S. BUCY
Certified Shorthand Reporter #187
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