20010913Puc8291.v1.doc

1 BOISE, IDAHO, WEDNESDAY, AUGUST 29, 2001, 9:00 A. M.

2

3

4 COMMISSIONER KJELLANDER: Well, good

5 morning. We'll be back on the record and I believe when we

6 left yesterday we were ready for the Deputy Attorney

7 General representing Staff to call her next witness.

8 MS. NORDSTROM: Thank you. Staff calls Terri

9 Carlock.

10

11 TERRI CARLOCK,

12 produced as a witness at the instance of the Staff, having

13 been first duly sworn, was examined and testified as

14 follows:

15

16 DIRECT EXAMINATION

17

18 BY MS. NORDSTROM:

19 Q Good morning.

20 A Good morning.

21 Q Please state your name and spell your last

22 name for the record.

23 A Terri Carlock, C-a-r-l-o-c-k.

24 Q By whom are you employed and in what

25 capacity?

313

CSB REPORTING CARLOCK (Di)
Wilder, Idaho 83676 Staff

1 A The Idaho Public Utilities Commission as

2 audit section supervisor.

3 Q Are you the same Terri Carlock that filed

4 direct testimony on July 20th and prepared Exhibits

5 Nos. 108 through 131?

6 A I am.

7 Q Do you have any corrections or changes to

8 your testimony or exhibits?

9 A Yes, I do have a few corrections. The first

10 two represent typos. On page 14, line 5, the year "2001"

11 should have been the year "2000."

12 MR. RIPLEY: I'm sorry.

13 THE WITNESS: Page 14, line 5.

14 MR. RIPLEY: Thank you.

15 THE WITNESS: On page 17, line 13, the word

16 "not" should be deleted, and I have replacement pages for

17 Exhibit No. 112, pages 2 through 6. There were some total

18 numbers that were inappropriately printed. That does not

19 change anything in my exhibit or in my testimony.

20 MS. NORDSTROM: May I approach with the

21 corrected exhibit?

22 COMMISSIONER KJELLANDER: Yes, you may.

23 (Ms. Nordstrom distributing documents.)

24 Q BY MS. NORDSTROM: Were those all the

25 connections you had?

314

CSB REPORTING CARLOCK (Di)
Wilder, Idaho 83676 Staff

1 A Yes.

2 Q If I were to ask you the questions set out in

3 your prefiled testimony as corrected, would your answers be

4 the same today?

5 A They would.

6 MS. NORDSTROM: I would move that the

7 prefiled direct testimony of Terri Carlock be spread upon

8 the record in its entirety as if read and Exhibits 108

9 through 131 be marked for identification.

10 COMMISSIONER KJELLANDER: Without objection,

11 we'll spread the testimony of Terri Carlock on the record

12 and we'll also have 108 through 131 -- was that correct?

13 MS. NORDSTROM: Correct.

14 COMMISSIONER KJELLANDER: Thank you.

15 -- admitted for the record.

16 (Staff Exhibit Nos. 108 - 131 were

17 admitted into evidence.)

18 (The following prefiled testimony of

19 Ms. Terri Carlock is spread upon the record.)

20

21

22

23

24

25

315

CSB REPORTING CARLOCK (Di)
Wilder, Idaho 83676 Staff

1 Q. Please state your name and address for the

2 record.

3 A. My name is Terri Carlock. My business

4 address is 472 West Washington Street, Boise, Idaho.

5 Q. By whom are you employed and in what

6 capacity?

7 A. I am employed by the Idaho Public Utilities

8 Commission as the Accounting Section Supervisor.

9 Q. Please outline your educational background

10 and experience.

11 A. I graduated from Boise State University in

12 May 1980, with a B.B.A. Degree in Accounting and in

13 Finance. I have attended various regulatory,

14 accounting, rate of return, economics, finance and

15 ratings programs. I chaired the National Association of

16 Regulatory Utilities Commissioners (NARUC) Staff

17 Subcommittee on Economics and Finance for over 3 years.

18 Under this subcommittee, I also chaired the Ad Hoc

19 Committee on Diversification. Since joining the

20 Commission Staff in May 1980, I have participated in

21 audits, performed financial analysis on various

22 companies and have presented testimony before this

23 Commission on numerous occasions.

24 Q. What is the purpose of your testimony in

25 this proceeding?

316

CARLOCK, T (Di) 1
07/20/01 Staff

1 A. The purpose of my testimony is to address

2 the issues identified in Order No. 28722, IPC-E-01-7 and

3 IPC-E-01-11 for Idaho Power Company (Idaho Power,

4 Company). These issues are trading practices (to

5 include hedging, transmission and wheeling charges, Mid-

6 C pricing and the use of weighted average pricing) and

7 what has been termed the November trading event. All of

8 these issues pertain to Case No. IPC-E-01-7 and IPC-E-

9 01-11. The trading practices going forward pertain to

10 Case No. IPC-E-01-16.

11 In initiating the present investigation

12 regarding the $51.235 million of disputed power

13 purchases, the Commission intended to investigate the

14 Company's "trading practices (to include hedging,

15 transmission and wheeling charges, Mid-C pricing, and

16 the use of weighted average pricing)". Order No. 28722

17 at 17. In the prefiled direct testimony of several of

18 its witnesses, the Company asserts that Staffs

19 challenge to the Company's trading practices in the

20 2000-2001 PCA year is contrary to prior Commission

21 Orders. The Staff does not agree with some of the

22 characterization or inferences drawn from these

23 interpretations of prior Commission Orders.

24 In particular, the Company maintains that

25 the hedging and use of the Mid-C Price Index for day-

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CARLOCK, T (Di) 2
07/20/01 Staff

1 ahead and real-time purchases were "previously reviewed

2 and agreed to between Idaho Power and Staff and formally

3 approved by the Commission in Order No. 28596 in Case

4 No. IPC-E-00-13." Idaho Power Response to Comments at

5 p. 8. As discussed later in more detail, Staff

6 disagrees with Idaho Power's characterization that the

7 Price Index Mechanism is not subject to review.

8 Staff recommends the assignment to the

9 non-operating entity and therefore no recovery from Idaho

10 customers of both the November transaction amount of

11 $7,976,701 and the excess transfer pricing for power of

12 $51,234,902 (Idaho jurisdictional numbers). These

13 adjustments follow normal regulatory practices intended

14 to protect customers from potential affiliate abuse.

15 Staff further recommends Idaho Power establish and

16 implement additional objectives and safeguards prior to

17 acceptance of the Index pricing mechanism in future Power

18 Cost Adjustment cases.

19

20 POWER COST ADJUSTMENT OVERVIEW AND HISTORY OF TRADING

21 PRACTICES

22 Q. Please provide an overview of the Power Cost

23 Adjustment (PCA) mechanism.

24 A. The PCA is a regulatory mechanism that

25 allows for annual recovery or rebate of 90 percent of

318

CARLOCK, T (Di) 3
07/20/01 Staff

1 power costs differing from those already included in

2 rates. The PCA rate adjustment has two components.

3 First, power cost differences are projected each spring

4 based on known snowpack. Second, differences between

5 the projection and actual costs are tracked and trued-up

6 in the following year. Inaccuracies in the projection

7 can cause large after-the-fact true-up adjustments.

8 Actual power costs come from the Company's books and are

9 verified by Staff audit each spring. By its nature, the

10 mechanism allows for deferral of the costs and recovery

11 after the fact. The majority of the audit verification

12 takes place with the true up portion after the fact.

13 Once the audit is complete, the Commission determines the

14 amount of the deferral to authorize for recovery.

15 Q. Has the PCA mechanism changed since it was

16 first implemented in 1993?

17 A. Although the basic PCA framework remains

18 essentially the same, the PCA has evolved and changed over

19 the years. Several of these changes are discussed in

20 Company witness Greg Said's prefiled direct testimony at

21 pages 9 - 16.

22 When Idaho Power entered the speculative

23 commodity trading business for non-system purposes in

24 1996, the accounting and reporting was not sufficient to

25 adequately separate trades between system and non-system

319

CARLOCK, T (Di) 4
07/20/01 Staff

1 purposes. In Staff comments dated May 7, 1999, Case No.

2 IPC-E-99-3 (Staff Exhibit No. 108, p. 3), Staff

3 specifically addressed its concern with the Company's

4 inability to accurately make this separation. Staff

5 continued to express its concerns in the IPC-E-01-7 and

6 IPC-E-01-11 Staff comments dated April 16, 2001.

7 Each year since 1996 when non-system trading

8 activities began, Idaho Power made some changes to the

9 way the separations were made. These changes were often

10 made during the PCA year. Staff reviewed the changes

11 after the fact and accepted them or made recommendations

12 for further changes. Most of this process occurred

13 between the Staff and Company during the audit. Other

14 interested parties also participated at times. Changes

15 were also made by Idaho Power to the pricing mechanism

16 used to make the separations. These changes were not

17 prospective but reviewed as part of the PCA. The

18 prudence of all transactions was always reviewed after

19 the fact during the true up phase of the PCA. Staff

20 reviewed the transactions based on the information

21 available at the time that the decision was made.

22 Q. Staff made an adjustment for approximately

23 $51 million associated with the transfer price from the

24 non-system operation to the regulated system. Please

25 explain why.

320

CARLOCK, T (Di) 5
07/20/01 Staff

1 A. The market price is not reflective of a

2 reasonable price surrogate between the system and non-

3 system for the intra-month purchases. The transfer price

4 between affiliates must be shown to be reasonable.

5 To compensate for this change, Staff

6 proposes to modify the pricing mechanism for the 2000 -

7 2001 PCA year for intra-month to more accurately reflect

8 the total cost. The non-system purchases were less

9 costly overall than the system purchases at market

10 index. Since these transactions are with a speculative

11 arm of IDACORP (regardless of whether IES was a part of

12 Idaho Power or a separate subsidiary dealing with Idaho

13 Power), Idaho Power must show the continued

14 reasonableness of the transfer prices. The lower-of-

15 cost or market for purchases and the higher-of-cost or

16 market for sales is the standard default pricing

17 mechanism used for regulated entities when a proper

18 pricing mechanism between affiliates entities has not

19 been justified.

20 Enhanced audit steps are performed to review

21 affiliate transactions and to protect customers from

22 possible affiliate manipulation. In connection with the

23 stipulation made in Case No. IPC-E-00-13 and reflected

24 in Order No. 28596, it was clear that continued review

25 of the pricing mechanism would occur. This assurance

321

CARLOCK, T (Di) 6
07/20/01 Staff

1 was provided to address the concerns of parties in the

2 case related to the affiliate contract and contract

3 pricing.

4 Q. Please compare system and non-system term

5 transactions.

6 A. Term transactions were implemented for non-

7 system purposes but effectively stopped for system

8 purposes after September 2000. Staff is concerned that

9 Idaho Power has substantially limited long-term power

10 contracts (i.e., in excess of one month) for the system-

11 operating book. Confidential Staff Exhibit No. 109

12 shows the actual system purchases. This exhibit shows

13 no term purchases for January and February 2001 as shown

14 in Columns 3 and 4. Long-term purchases entered prior

15 to the IES contract, account for minor term purchases

16 for the system in Columns 5 and 6. Confidential Staff

17 Exhibit No. 110 shows the actual non-system purchases of

18 approximately 80% for January and February 2001.

19 Confidential Staff Exhibit Nos. 111 and 112 reflect the

20 sales transactions. All Exhibit Nos. 109 through 112

21 show graphs to reflect the day ahead, real time, term

22 and total transactions for the 2000 - 2001 PCA year.

23 The ability to purchase power at a fixed

24 price is a valuable tool for rate stability. In the

25 past, the Company has purchased large amounts of power

322

CARLOCK, T (Di) 7
07/20/01 Staff

1 at relatively inexpensive prices to serve its load.

2 This is a change in activity and operations that was not

3 expected. On the contrary, the parties were assured

4 during the Company's workshops that the operations would

5 not change.

6 Q. Isn't it reasonable to expect non-system

7 transactions to differ from system transactions due to

8 the increased level of risk the non-system may be

9 willing to bear?

10 A. Yes, the magnitude of the transactions would

11 differ. The non-system may execute additional and

12 potentially more risky deals. However, the direction

13 and the existence of transactions should be consistent.

14 Therefore, since the non-system executed term

15 transactions, the system should have had some

16 corresponding transactions within its risk bands.

17 Term transactions reduce the price

18 variability and usually the cost for that time period.

19 Since the term transactions were effectively stopped for

20 the system, the cost to customers was higher. The power

21 purchases were shifted to intra-month and priced at the

22 market index.

23 Q. Please describe the background events leading

24 to the Company's current trading practices?

25 A. Company witness Sharon Hoyd outlines the

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CARLOCK, T (Di) 8
07/20/01 Staff

1 development of wholesale power markets following FERC's

2 issuance of Order Nos. 888 and 889 in 1996. As she

3 explains in her prefiled direct testimony at pages 3 -

4 11, while the development of markets and the use of

5 various market devices such as futures and options

6 increased, the accounting industry was also developing

7 more stringent accounting rules. The purpose of these

8 new accounting rules was to appropriately separate the

9 buying and selling of energy for utility operation from

10 the buying and selling of energy for trading or

11 speculative purposes. Eventually, the Financial

12 Accounting Standards Board (FASB) and its Emerging

13 Issues Task Force (EITF) promulgated Generally Accepted

14 Accounting Principles (GAAP) for these transactions.

15 The adoption of accounting standards resulted in the

16 issuance of Statement of Financial Accounting Standards

17 (SFAS) 133, SFAS 138, and EITF 98-10.

18 Q. What do these standards require?

19 A. I agree with Ms. Hoyd's explanation that:

20 EITF 98-10 was written to give
clarification between energy contracts
21 and energy trading contracts for
accounting purposes. SFAS 133 and SFAS
22 138 were written to ensure that all
obligations with market price exposure
23 are reflected in the financial
statements.
24

25

324

CARLOCK, T (Di) 9
07/20/01 Staff

1 Hoyd Prefiled Direct Testimony at 7, ll. 7-11

2 (emphasis added).

3 Q. Did the Company and Staff discuss the

4 adoption and application of these new accounting

5 standards to Idaho Power?

6 A. Yes. In a letter dated March 18, 1999 to

7 the then administrator of the Staff's Utility Division,

8 Company witness Ric Gale stated that the Company was

9 changing its classification and reporting of purchase

10 and sales transactions relating to its power trading

11 operations. Staff Exhibit No. 113 at p. 1. In

12 particular, transactions (including purchases and sales)

13 pertaining to "the balancing of the [Company's] System

14 load and . . . system reliability are classified as

15 'system' [transactions]." Id. Conversely, transactions

16 not related to the balancing of the system load and

17 resources are classified as "non-system" transactions.

18 Id. Idaho Power requested that the administrator

19 provide a "letter indicating the Commission's

20 acknowledgement of these changes." Id.

21 Q. Did the administrator forward a letter to

22 the Company?

23 A. Yes. In a April 7, 1999 letter to Mr. Gale,

24 Stephanie Miller (the Utilities Division Administrator)

25 noted that the Commission understands the Company's

325

CARLOCK, T (Di) 10
07/20/01 Staff

1 implementation of the system and non-system accounting.

2 Idaho Power Exhibit No. 9. Her letter stated that the

3 Commission "does not take exception to the described

4 accounting changes but reserves judgment on ratemaking

5 issues related to the exclusions of these [non-system,

6 marked-to-market] transactions from the PCA." Id.

7 Q. What was the next historical event?

8 A. As a result of implementing the accounting

9 changes, the Company in the 1999-2000 PCA case (Case No.

10 IPC-E-99-3) separated power transactions for the months

11 of January, February, and March 1999 into operating and

12 non-operating transactions. Idaho Power Exhibit No. 7,

13 Order No. 28049 at 2. The Order further recites that

14 the Staff asserted in its comments that "it is unable to

15 reach any firm conclusions about future effects of

16 removing the non-operating power marketing transactions

17 from the PCA." Id. At 3.

18 In that PCA case, the Industrial Customers

19 of Idaho Power (ICIP) also expressed concern that

20 removal of the non-operating sales from the PCA would

21 remove the revenue accruing to ratepayers from such

22 sales. Id. "The ICIP is concerned that Idaho Power's

23 management has every incentive to maximize the amount of

24 sales removed from the PCA while minimizing the amount of

25 expenses removed." Id.

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CARLOCK, T (Di) 11
07/20/01 Staff

1 Likewise, FMC (now Astaris) expressed

2 similar concerns. In particular, the Order recites that

3 FMC insisted that "ratepayers are entitled to assurances

4 that costs are properly allocated to the Company's

5 competitive activities and the ratepayers are

6 compensated for any use of utility resources to support

7 the speculative trading." Idaho Power Exhibit No. 7,

8 Order No. 28049 at 4.

9 The Commission agreed with FMC and ICIP

10 that:

11 Adequate safeguards must be in place to
ensure that the Company's ratepayers
12 are protected from the risks associated
with such [speculative trading]
13 activities. We believe that it is
premature to conduct a formal hearing
14 relating to this issue but agree that
further consideration of this issue is
15 warranted. We direct the Commission
Staff to coordinate with Idaho Power,
16 FMC, the ICIP and all other interested
persons to determine, informally, how
17 best to address the issue. Those
parties might consider conducting a
18 workshop. If necessary, any or all of
them are free to petition this
19 Commission to initiate a formal case.
Regardless, we expect that some written
20 work product will ultimately emanate
from the efforts of the parties
21 containing an analysis of the issue and
a recommendation regarding what action,
22 if any, is needed by this Commission.

23 Idaho Power Exhibit No. 7, Order No. 28049 at 5.

24 Q. Following the issuance of this Order on May

25 14, 1999, did the parties participate in a workshop?

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CARLOCK, T (Di) 12
07/20/01 Staff

1 A. Yes. As verified by Company witness Said on

2 page 14 of his prefiled direct testimony, a workshop was

3 held on September 23, 1999.

4 Q. Did the workshop result in a "written work

5 product"?

6 A. Yes. Staff Exhibit No. 114 reflects the

7 memorandum dated February 14, 2000 the Staff submitted a

8 two-page memorandum with four attachments representing

9 written materials filed by Idaho Power, the Commission

10 Staff, ICIP, and Astaris. Staff's written report

11 labeled as Attachment D (Staff Exhibit No. 114, pgs. 51

12 - 56), noted that Staff examined the off-system

13 transactions for only the month of August 1999 "and

14 finds the adjusted Mid-C average daily price to be an

15 acceptable price to use for these inter-book transfers.

16 . . . The Staff concluded that the Mid-C price with the

17 transmission adjustment is a fair and just pricing

18 mechanism to use for the inter-book transfer [between

19 operating and non-operating books of Idaho Power]." Staff

20 Exhibit No. 114, p. 51.

21 The Staff Report also noted that Idaho Power

22 customers "are not necessarily benefiting from the

23 relationship shared with the energy trading activities."

24 Id. Prior to the end of revenue sharing on December 31,

25 1999, customers shared the risks and any benefits from

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CARLOCK, T (Di) 13
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1 the energy trading contracts. Staff concluded that new

2 discussions between the parties needed to be held to

3 discuss risk, rewards, and allocations in basic rates.

4 Q. Was the Staff memorandum dated February 14,

5 2000 submitted into the 1999-2000 PCA case record?

6 A. No, however, in Order No. 28358 issued May

7 9, 2000, the Commission acknowledged that the Staff

8 Report was previously filed with the Commission.

9 However, the mention of the Staff Report addressed only

10 ICIP's recommendation that the Commission initiate a new

11 proceeding "to consider changes to rate structure for

12 Idaho Power." Staff Exhibit No. 115, Order No. 28358 at

13 5.

14 Q. Did the 1999-2000 PCA Order No. 28358 (Case

15 No. IPC-E-00-6) address hedging or the use of the Mid-C

16 Price Index?

17 A. No. For this reason, the Commission should

18 not infer from Greg Said's prefiled direct testimony at

19 page 15, lines 6 - 16, that the Commission did so. The

20 Commission "acknowledged the Staff memorandum addressing

21 the accounting change concerns raised by opposing

22 parties." But as he indicates in the next sentence, the

23 accounting change alluded to by the Commission Order No.

24 28358 concerns the separation of "energy contracts"

25 /

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CARLOCK, T (Di) 14
07/20/01 Staff

1 (i.e., operating transactions) from "energy trading

2 contracts" (i.e., non-operating transactions).

3 Q. What happened next?

4 A. IDACORP created the IDACORP Energy Solutions

5 affiliate (IES) to be responsible for natural gas

6 commodity trading. IDACORP expanded the IES duties to

7 include the wholesale power market purchases and sales

8 for Idaho Power. To formalize the relationship between

9 the non-regulated affiliate (IES) and the regulated

10 utility (Idaho Power), the Company filed an application

11 on September 1, 2000 requesting approval of a proposed

12 Electric Supply Management Service Agreement ("the

13 Agreement") between Idaho Power and IES. This was

14 assigned Case No. IPC-E-00-13.

15 Q. In their prefiled direct testimonies Company

16 witnesses Said and Gale imply that Commission Order No.

17 28596 in Case No. IPC-E-00-13 authorized the Company to

18 utilize Mid-C Price Index for real-time and day-ahead

19 transactions. Staff Exhibit No. 116, Order No. 28596.

20 Do you concur with these assessments?

21 A. No, I believe the Company's reliance upon

22 this Order is premature for several reasons. First, in

23 the IPC-E-00-13 case, Idaho Power filed an application

24 requesting approval of the proposed Agreement between

25 Idaho Power and its unregulated affiliate, IES. Staff

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CARLOCK, T (Di) 15
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1 Exhibit No. 117. What the Staff and Company do agree

2 upon is that Order No. 28596 approved the adoption of

3 the proposed Agreement. Where the Company and Staff

4 disagree is the effect of the adoption.

5 It is Staff's contention that by its

6 explicit terms the Agreement and its Statement of

7 Services (including use of the Mid-C Price Index in

8 5.1 of the Statement of Services) were not effective.

9 Staff Exhibit No. 117 at p. 7. However, paragraph 9 of

10 the Agreement provides

11 9. Commission Approval. This
Agreement and any future amendments
12 shall not become effective until the
Commissions have issued their
13 respective final orders approving the
agreement or any future amendments. If
14 the final orders of any of the
Commissions initially approving this
15 agreement contain material terms or
conditions that either party finds
16 unacceptable, within fourteen (14) days
of the issuance of the order, the
17 adversely affected party will have the
right to cancel this agreement by
18 giving thirty (30) days written notice
of cancellation to the other party.
19

20 Staff Exhibit No. 117 p. 7 (Agreement 9 at p. 4)

21 (emphasis added). The term "Commissions" specifically

22 include the Idaho Public Utilities Commission, the

23 Oregon Public Utilities Commission, and the Federal

24 Energy Regulatory Commission. Staff Exhibit No. 117 at

25 6 p. 7. Given the explicit terms of the Agreement, it

331

CARLOCK, T (Di) 16
07/20/01 Staff

1 is Staff's position that its operating terms, including

2 the use of the Mid-C pricing mechanism, were not

3 effective at the time this Commission issued its Order

4 No. 28596 approving the Agreement on December 19, 2000.

5 Q. When did the Agreement become effective?

6 A. By its own terms, the Agreement did not

7 become effective until the Oregon PUC and FERC approved

8 the Agreement. FERC conditionally approved the

9 Agreement effective April 28, 2001. See Exhibit No. 118

10 (95 FERC 61,147 (2001)). FERC did not approve the

11 Agreement as initially submitted. Instead, FERC

12 required the Agreement to be modified to reflect that

13 the Mid-C Price Index be used for real-time transactions.

14 Staff Exhibit No. 118 at pp. 1-2. On May 14, 2001, Idaho

15 Power and IES filed the requisite change

16 to its pricing of real-time transactions. Staff Exhibit

17 No. 119.

18 Q. When did the Oregon Commission approve the

19 Agreement?

20 A. The Oregon PUC did not issue its approval

21 until July 3, 2001. Staff Exhibit No. 120. Thus, under

22 the terms of the Agreement, it was not effective until

23 July 3, 2001 -- well after the end of the 2000-2001 PCA

24 year.

25 /

332

CARLOCK, T (Di) 17
07/20/01 Staff

1 Q. Has the Company submitted the FERC required

2 change to the Agreement for this Commission's approval?

3 A. As of July 20, 2001, the Company had not

4 filed an application requesting that the Idaho

5 Commission approve the FERC required amendments to the

6 Agreement.

7

8 The Pricing Mechanism and Disputed $51 Million

9 Q. Did the Company provide any rationale for

10 why it utilized the pricing mechanism contained in the

11 Agreement even though the Agreement was not effective?

12 A. In Company witness Gale's direct prefiled

13 testimony in the combined IPC-E-01-7 and IPC-E-01-11

14 cases, he was asked a question about when the Company

15 implemented any of the pricing mechanisms included in the

16 Agreement. He replied:

17 Yes, the Company adopted the transfer
price for real-time hourly transactions
18 once the IPUC approved the Electric
Supply Management Agreement. This
19 change was implemented not because the
Agreement had become effective, but
20 because once the Agreement and the
transfer pricing were approved by the
21 IPUC, the Company viewed the new real-
time transfer price as the appropriate
22 price.

23 Prefiled Direct Testimony Gale at p. 6, ll. 10 -

24 16.

25 /

333

CARLOCK, T (Di) 18
07/20/01 Staff

1 Q. Was the Company's use of the Mid-C Index

2 effective on a going forward basis as of the date of the

3 IPC-E-00-13 Order, December 19, 2000?

4 A. No. Mr. Gale indicates that the Company

5 made the change to real-time hourly pricing in December

6 2000. However, Company witness Hoyd testified the Mid-C

7 pricing methodology was used to calculate its power

8 purchase cost from April 2000 for the PCA calculation.

9 Hoyd Prefiled Direct Testimony at 21, ll. 5-9.

10 Q. Idaho Power states that the market pricing

11 mechanism it used was approved in Order No. 28596, Case

12 No. IPC-E-00-13. Why should that be changed for the

13 2000-2001 PCA year?

14 A. As previously stated, the allocations,

15 separations and pricing mechanisms used in the PCA over

16 the years has evolved. These changes may have been for

17 part of a PCA year or for the full PCA year. Each year

18 the prior year mechanism was reviewed for reasonableness

19 in the true-up audit.

20 The Staff audit function and the Company's

21 requirement to demonstrate the continued reasonableness

22 of market pricing was the safeguard proposed and adopted

23 by parties as part of the workshops and stipulation in

24 IPC-E-00-13. Even with this safeguard, the Industrial

25 Customers of Idaho Power remained uncomfortable with the

334

CARLOCK, T (Di) 19
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1 mechanism and did not sign the stipulation. It would

2 not have been acceptable to Staff and other parties to

3 endorse a 5-year contract between the parties without

4 the burden remaining on the Company to show the

5 continued reasonableness of the Mid-C Index as a

6 surrogate for price.

7 The simple fact is that even if the

8 Agreement had been in effect, the Company did not comply

9 with the agreed upon documentation, oversight manager,

10 and audit tracking mechanisms safeguards necessary to

11 justify the reasonableness of its market-priced

12 transactions.

13 Q. Was the retention of documentation of

14 marketing transactions and decision-making a concern?

15 A. Yes. The lack of documentation retained by

16 Idaho Power to support the decisions was a concern

17 expressed during the audits since 1997, in Staff

18 comments and during subsequent workshops. This lack of

19 retained documentation continues to be a concern in this

20 case.

21 The documentation concern now pertains to

22 the pricing mechanism in addition to the

23 assignment/allocation of transactions between system and

24 non-system. Approval of the pricing mechanism in Case

25 No. IPC-E-00-13 was prefaced on the continued review and

335

CARLOCK, T (Di) 20
07/20/01 Staff

1 ongoing improvements to the process. This is no

2 different than the process that had always been followed

3 between the Staff and Idaho Power for the PCA review.

4 In the instant cases, IPC-E-01-7 and IPC-E-01-11, the

5 dollar magnitude is greater. The increase in this

6 magnitude is partially due simply to the increase in

7 transactions entered into by Idaho Power and now its

8 affiliate IDACORP Energy. Any time transactions occur

9 between affiliates, the necessary review and

10 documentation required for separations, allocations or

11 the pricing products are enhanced. Failure to require

12 enhanced scrutiny of affiliate transactions could allow

13 increased costs to be charged customers by manipulation

14 of the affiliate relationship.

15 When Staff conducted its true-up audit of

16 Company transactions made during the 2000-2001 PCA year,

17 it discovered pricing concerns related to the ongoing

18 reasonableness of using the Index pricing as a

19 surrogate. These concerns must be corrected by

20 allocating the higher transfer prices to the non-

21 regulated operations. To this end, Staff recommends

22 non-recovery of the $51,234,902 (Idaho jurisdictional

23 amount).

24 Proper safeguards must be implemented to

25 address and eliminate these issues in the future. Once

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CARLOCK, T (Di) 21
07/20/01 Staff

1 objectives and safeguards are approved and in place,

2 future true-up audits for prudence will focus on

3 compliance with these objectives and safeguards.

4 Q. Are there other reasons why the Commission

5 should adopt the Staff's adjustment to power costs

6 rather than using of the Mid-C Price Index?

7 A. Yes. Restricted to its context in the Case

8 No. IPC-E-00-13, the Staff and the Company suggested

9 that use of published market indices is an appropriate

10 method for pricing transactions between regulated and

11 non-regulated affiliates. However, IES was not licensed

12 by FERC to conduct trading activities until it received

13 FERC approval on April 27, 2001. See Staff Exhibit No.

14 118. The trading was performed under Idaho Power's

15 authority. The point here is that until the Commissions

16 and FERC approved the Agreement between IES and Idaho

17 Power, all power purchases were made by Idaho Power not

18 IES. Because Idaho Power was purchasing energy for

19 itself, ratepayers should not pay a price for that power

20 that is significantly higher than its cost, even if the

21 "price" was the market index.

22 Idaho Power was asked in audit requests to

23 supply vouchers, invoices or documentation supporting

24 compliance with the terms of the contract. The Company

25 responded that the contract was not in effect since it

337

CARLOCK, T (Di) 22
07/20/01 Staff

1 lacked the required approvals. Consequently, the

2 Company insisted the other provisions had not yet taken

3 effect. The other provisions -- $2 million annual

4 credit, Idaho Power Oversight manager, implementation of

5 audit tracking mechanisms -- were safeguards to insulate

6 customers from potential affiliate abuse.

7 Even though the Company utilized the pricing

8 mechanisms contained in the Agreement, the Company did

9 not credit Idaho retail customers with the stipulated $2

10 million. Direct Testimony of witness Gale, Case Nos

11 IPC-E-01-7 and IPC-E-01-11 testimony at p. 4, ll. 6 -

12 9.) John R. Gale, Vice-President of Regulatory Affairs,

13 notified the Commission in a letter dated June 29, 2001

14 that the "commitment to initiate the flowback

15 obligation" of $2 million annually, would go into effect

16 on July 1, 2001. Staff Exhibit No. 121. Consequently,

17 the pricing mechanism should go into effect no sooner

18 than that date.

19 Q. Is it possible for a pricing mechanism to be

20 reasonable at one point in time but not at another time

21 period?

22 A. Yes. As markets change and the relationship

23 between affiliated interests change, it is possible for

24 a pricing mechanism to be reasonable at one point in

25 time but not at another. The magnitude of transactions

338

CARLOCK, T (Di) 23
07/20/01 Staff

1 also impacts the possibility that the reasonableness may

2 change. When the level of market participation and the

3 dollar prices are small, the transactions'

4 reasonableness is more likely to fall within an

5 acceptable band. As the transactions change, the level

6 of activity and the price increase. This exacerbates

7 the differences between a surrogate or market price and

8 the actual cost of the affiliate beyond an acceptable

9 band, making it so the market price is no longer

10 reasonable.

11 Q. Please explain the calculation for the

12 pricing adjustment recommended by Staff.

13 A. For the months of December 2000, January 2001

14 and February 2001, Staff has re-priced the day-

15 ahead power purchased from the Non-Operating System to

16 the System at the daily weighted average price paid by

17 the Non-Operating System. That way, the System pays

18 exactly what the Non-Operating System pays. The Non-

19 Operating System should not be allowed to profit

20 substantially from the regulated system. Staff believes

21 that the weighted average price is fair and reasonable.

22 It provides incentive to make sure that all trades are

23 sound and reasonable for both the system and non-system

24 transactions with minimal ability to game or manipulate

25 the price. Substantially greater margins on similar

339

CARLOCK, T (Di) 24
07/20/01 Staff

1 transactions for a non-regulated entity compared to a

2 regulated entity is an indicator of an improper pricing

3 mechanism. The magnitude of this adjustment is shown on

4 Staff Confidential Exhibit Nos. 122 - 127. Staff

5 Confidential Exhibit No. 122 shows the daily record for

6 December 2000, Staff Confidential Exhibit No. 123 shows

7 the daily record for January 2001, and Staff

8 Confidential Exhibit No. 124 shows the daily record for

9 February 2001.

10 Consistent with the adjustment for the

11 detailed audit for the three months listed above, Staff

12 determined that the rest of the day ahead power for the

13 PCA year should be re-priced using a weighted average

14 monthly price. While not as precise as a daily price,

15 Staff believes it is fairly representative. These

16 months were not audited on a day by day basis due to

17 time constraints. The months of August and September

18 2000 did not have adjustments, the transfer prices were

19 already at the lower of cost or market, when compared to

20 the weighted average monthly price for purchases, and at

21 the higher of cost or market for sales. This adjustment

22 is shown on Staff Confidential Exhibit No. 125 for the

23 months of April through November 2000.

24 Staff has made adjustments to the day ahead

25 transactions for the months of April 2000 through

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CARLOCK, T (Di) 25
07/20/01 Staff

1 February 2001, with the exception of the months of

2 August and September, and included them in the Non-Firm

3 Purchases and Surplus Sales, Lines 19 and 20 of the PCA

4 calculation on Company Exhibits 1 and 3 of Case Nos.

5 IPC-E-01-07 and IPC E-01-11, respectively. The net

6 adjustment, before the jurisdictional and sharing

7 allocations, and without the effect of interest on the

8 deferral balance for the day ahead transactions is

9 ($61,467,386.84). The Idaho jurisdictional number is

10 $51,234,902. This represents a benefit to the customer.

11 The calculation is summarized on Staff Exhibit No. 128.

12 In December 2000, the Company changed the

13 way the Real Time Transactions were priced. In the

14 past, the transactions always flowed through the system

15 at their actual cost. Now, however, the transactions

16 are priced based on the weighted average price of all

17 real time transactions that touch the Idaho Power system

18 on an hourly basis. According to Staff's analysis, this

19 has also resulted in overcharges and underpayments in

20 several cases. Staff has re-priced the real time

21 purchase transactions for the months of December 2000

22 through February 2001 to the lower of the Non System's

23 cost or market price. Staff has also re-priced the real

24 time sale transactions for the same months using the

25 higher of sales price or market. Staff believes that

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CARLOCK, T (Di) 26
07/20/01 Staff

1 purchases and sales should be kept separate and that the

2 system should get the benefit of the best price.

3 The Staff made adjustments to the inter-book

4 real time sales and purchases for the months of December

5 2000, and January and February 2001. The net

6 adjustment, before the jurisdictional and sharing

7 allocations, and without the effect of interest on the

8 deferral balance, for the real time transactions are

9 ($4,666,381.95). This represents a benefit to the

10 customer. The calculation is shown on Staff

11 Confidential Exhibit Nos. 122 - 125 and summarized on

12 Staff Exhibit No. 128.

13 NOVEMBER TRANSACTION

14 Q. Please explain what has been termed the

15 'November transaction'.

16 A. The 'November transaction' is the

17 transaction identified by Staff during the PCA audit as

18 an adjustment in the true up. The Risk Management

19 Committee (RMC) Minutes reflected a term transaction for

20 the system that was not completed. Staff adjusted the

21 PCA results as if that transaction were completed

22 resulting in a recommended removal of the higher priced

23 replacement power from the recommended increase. Idaho

24 Power claims the transaction was not completed because

25 the RMC changed its decision later during the same

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CARLOCK, T (Di) 27
07/20/01 Staff

1 meeting. The continued Staff review of this transaction

2 and the explanation by Idaho Power does not change the

3 Staff position.

4 Q. Please explain the operating plan.

5 A. The operating plan is a primary planning

6 tool used by Idaho Power to operate the system and is a

7 primary tool used by the RMC for its decision making

8 related to the system. The operating plans are the

9 documents provided to Staff to support the power

10 purchase transactions, sales transactions and the

11 decisions made by the RMC. The operating plans show the

12 forecasts under the expected scenario, a best scenario

13 and a worst scenario.

14 Q. What did the operating plans reveal that are

15 available for the time of the RMC meeting on November

16 21, 2000 when the purchase decision was made for

17 January?

18 A. The operating plans provided to Staff showed

19 that under almost every scenario the system would be

20 short in January. The RMC minutes and available

21 supporting documentation do not provide information to

22 counter the original decision to purchase power for the

23 system to cover the January shortage. Any subsequent

24 information on pricing or other data was not reflected

25 in the RMC minutes or retained to support the decisions

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CARLOCK, T (Di) 28
07/20/01 Staff

1 made. Absent this documentation, the change of decision

2 simply looks like a bad decision or an error that was

3 contrary to the prudent decision originally made, and

4 passes the detrimental cost to customers. These costs

5 should not be recovered from customers. The decision

6 not to purchase was made by the RMC and should be

7 absorbed by the non-system operations.

8 Staff has adjusted the amount of the

9 purchased power expenses in January 2001 by the total

10 system amount of $10,288,386, as shown on Staff

11 Confidential Exhibit No. 127, that would have been saved

12 if the RMC had completed the directive. All the

13 documentation supports a forward purchase of power for

14 the system. Rationale for a change of vote has not been

15 provided. It is reasonable for Staff to adjust the

16 purchase power expense to reflect the purchase as if it

17 had been made. To do otherwise would pass the result of

18 improper decision on to customers at their expense.

19 Q. Why does Staff find the Company's

20 explanation unpersuasive?

21 A. The operating reports available for review,

22 the RMC minutes, and the subsequent events referenced by

23 Idaho Power do not justify the reversal of this term

24 transaction. The subsequent events do not reflect the

25 same product for comparison. A longer-term product may

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CARLOCK, T (Di) 29
07/20/01 Staff

1 be packaged to get a better deal overall even when one

2 portion of the transaction would result in an imbalance

3 for the system. Idaho Power could have been short in

4 January but still packaged a deal that would sell power

5 for the first quarter in exchange for power in the third

6 quarter. These transactions are not mutually exclusive.

7 Q. In his testimony Darrel Anderson, Vice

8 President - Finance & Treasurer, Idaho Power Company,

9 explains why the system didn't need to purchase for

10 January 2001. Do you accept his explanation as a

11 protrayal of the complete facts?

12 A. No. Price trends from Idaho Power documents

13 also reflect forward prices for January 2001 increasing.

14 While there may be several reasons for any increase,

15 historical price trends were probably not the primary

16 consideration. Recent price increases for gas and

17 electricity caused decisions by most traders to be based

18 on other data, such as forward market prices, total

19 trading position of IDACORP and Idaho Power. Staff

20 Confidential Exhibit No. 129 summarizes the operating

21 plan forecasts and the forward market price data

22 available as documentation for RMC decisions. The

23 November transactions relates to the November 21, 2000

24 RMC meeting. The documentation retained includes the

25 operating plans for November 16, 2000 and November 28,

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CARLOCK, T (Di) 30
07/20/01 Staff

1 2001 but not anything in between.

2 Exhibit No. 129 shows the operating plan

3 documentation to sketch the transaction referred to by

4 Company witness Anderson for the forward sale of power

5 in the First Quarter of 2001 in exchange for the

6 purchase of power in the Third Quarter of 2001. If

7 market prices were higher in the third quarter than the

8 first quarter, Mr. Anderson's claim that they wouldn't

9 sell if short might not be completely accurate because

10 line 24 of Staff Exhibit No. 129 shows they completed

11 the opposite where they were buying for the third

12 quarter when September was forecasted to be long. This

13 exhibit shows how forward market prices and inventory

14 may have been greater factors for consideration than

15 absolute balance of the system forecasted need.

16 Q. Please explain how these problems can be

17 avoided in the future.

18 A. Proper documentation to support prudent

19 decisions should include information supporting the

20 decision or change in decisions and the rationale if the

21 decision made is not directly supported by the available

22 data. All charts or discussion papers must be retained

23 as support. The PCA review is conducted at least

24 annually. This is a reasonable time frame for the

25 Company to retain such documentation. If the decision

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CARLOCK, T (Di) 31
07/20/01 Staff

1 can not be shown to be prudent at the time it was made,

2 the associated expenses should not be recovered from the

3 regulated customer but should be assigned to the non-

4 system operation or recorded below the line.

5

6 REQUIRED OBJECTIVES AND SAFEGUARDS

7 Q. Please provide an overview of the objectives

8 you believe Idaho Power must implement related to

9 trading activities and risk management.

10 A. Idaho Power is responsible for providing

11 power at a reasonable cost to its customers. To assure

12 the costs are reasonable, Idaho Power must maintain

13 documentation and RMC minutes reflecting the data

14 available and considered in making its decisions. When a

15 product or service is provided to the regulated

16 utility from an affiliate or non-regulated operation,

17 the review by the Commission Staff of those transactions

18 must be enhanced. Therefore Idaho Power must retain and

19 provide additional documentation above that required for a

20 third-party transaction.

21 The objectives I recommend the Idaho Power

22 focus on include the following categories: 1) term

23 transaction decision management and documentation, 2)

24 forecasting documentation, 3) risk management profile

25 measures, 4) performance standards and 5) transfer of

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CARLOCK, T (Di) 32
07/20/01 Staff

1 value evaluations. These objectives, as further

2 discussed by Staff witness Thomas J. Lord, will provide

3 parties to Idaho Power cases additional opportunity to

4 review the decision making process of Idaho Power and

5 ensure that customers are paying reasonable prices for

6 power. The affiliate relationship and the transfer

7 pricing mechanisms are a major portion of the review

8 conducted by Staff and parties to assure the transfer

9 prices are and remain reasonable.

10 Q. Would you anticipate that the lower-of-cost

11 or market for purchases and the higher-of-cost or market

12 for sales continue now that IDACORP Energy is in full

13 operation and in separate facilities from Idaho Power?

14 A. I believe market pricing for the intra-month

15 transactions will be the appropriate pricing mechanism

16 once the control objectives are quantified and

17 operational. Staff recommends for the current filings,

18 IPC-E-01-7 and IPC-E-01-11 that the following pricing

19 mechanisms apply to all day ahead transactions:

20 1. Purchases by Idaho Power from the non-

21 operating book for the system should be priced at the

22 lower of cost or market. Staff recommends that the

23 market price continue to be based on the Mid-C price or

24 another acceptable pricing mechanism approved by the

25 Commission.

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CARLOCK, T (Di) 33
07/20/01 Staff

1 Staff further recommends that the cost be

2 based on the actual cost of the power, using a daily

3 weighted average of the price actually paid for the power

4 by the non-operating book to third parties.

5 2. Sales from Idaho Power from the operating

6 book to the non-operating book should be priced at the

7 higher of cost or market. Staff recommends that the

8 market price continue to be based on the Mid-C price or

9 another acceptable pricing mechanism approved by the

10 Commission.

11 Staff further recommends that the cost be

12 based on the actual price of power sold to third

13 parties.

14 These pricing recommendations will provide

15 the ratepayer with the assurance that they will not pay

16 rates based on prices that are unfair, unjust and

17 unreasonable.

18 The Company, Staff and other interested

19 parties should work together to develop the objectives

20 and safeguards. This is critical to ensure the

21 reasonableness of using an Index as a surrogate for

22 actual costs going forward in IPC-E-01-16. The

23 continued cooperative efforts are necessary to achieve a

24 workable solution. Idaho Power has informally indicated

25 they favor the proposed process. The resulting

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CARLOCK, T (Di) 34
07/20/01 Staff

1 objectives and safeguards should be presented to the

2 Commission for approval or rejection in the order issued

3 in Case No. IPC-E-01-16. These efforts will be made

4 between now and the hearing in these cases.

5 Absent appropriate safeguards, Staff will

6 continue to propose lower-of-cost or market for

7 purchases and the higher-of-cost or market for sales as

8 the only transfer pricing mechanism to assure there

9 in no affiliate manipulation and that customers are charged

10 fair, just and reasonable rates.

11 RISK MANAGEMENT COMMITTEE

12 Q. Please provide an overview of the Risk

13 Management Committee?

14 A. During the 2000 - 2001 PCA year, the Risk

15 Management Committee (RMC) consisted of IDACORP and

16 Idaho Power officers. These members are listed on

17 Exhibit No. 130 as provided in Response to Staff

18 Production Request No. 1. No member solely represented

19 the interests of Idaho Power and its customers.

20 According to Idaho Power, "The purpose of

21 the RMC is to maintain general oversight over all

22 commodity trading and financial risk management

23 operations." Response to Staff Production Request No.

24 3. The decision-making process of the RMC is explained

25 in Response to Production Request No. 4.

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CARLOCK, T (Di) 35
07/20/01 Staff

1 The RMC reviews operating proposals
prepared by Idaho Power Company
2 personnel. The proposals include
assumptions for supply and demand
3 requirements based on data available at
that time. Based on the results of
4 this data, the collective experience of
the committee members, other pertinent
5 internal and external data, and an in-
depth discussion between committee
6 members, decisions are made to
determine the need to buy or sell
7 energy. Numerous factors are considered
in coming to these decisions including
8 weather, expected load requirements,
current snowpack, transmission
9 availability, pricing and the overall
system portfolio position. When it is
10 determined that an action is required,
a recommendation is made by a committee
11 member and put to the entire RMC for a
vote. A majority is required to
12 confirm a transaction for inclusion in
the operating plan.
13

14 Staff expressed concern in its comments

15 filed on April 16, 2001 in these cases that the RMC

16 consists of the same members for both the utility and

17 for the non-regulated operations. Staff review of the

18 RMC minutes indicates that the Committee does not

19 consistently support a mandate to first take care of the

20 system needs before the non-regulated operations, even

21 though this is the stated policy. Based on a review of

22 the minutes, Staff believes that the RMC has not focused

23 enough energy on the utility and as a result, system

24 costs are higher than they otherwise would have been.

25 Recently the Risk Management Committee was

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CARLOCK, T (Di) 36
07/20/01 Staff

1 split into two committees, an IDACORP Energy Risk

2 Management Committee and an Idaho Power Risk Management

3 Committee. The current members of the committees are

4 listed on Exhibit No. 131. This split should allow the

5 respective committees to focus more directly on its

6 primary responsibilities. The non-operating group, now

7 IDACORP Energy can focus on non-regulated matters and

8 the Idaho Power RMC can focus on matters pertaining to

9 the regulated operations.

10 Q. Does this conclude your direct testimony in

11 these cases?

12 A. Yes, it does.

13

14

15

16

17

18

19

20

21

22

23

24

25

352

CARLOCK, T (Di) 37
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1 (The following proceedings were had in

2 open hearing.)

3 MS. NORDSTROM: Idaho Power's testimony has

4 called into question Ms. Carlock's testimony regarding her

5 calculations for the day-ahead transactions. Additional

6 direct testimony is needed to clarify what calculations she

7 did and how she did them and to respond to Ms. Hoyd's

8 Exhibit 30 that was submitted yesterday. The Staff

9 requests the Commission's indulgence to allow this

10 additional direct testimony.

11 MR. RIPLEY: Well, without knowing anything

12 more than what just counsel has set forth, we must object.

13 We have no time to prepare. We don't even have any idea

14 what the testimony is going to say for sure. The

15 Commission's Orders were very specific in this proceeding

16 as to what should occur as far as the filing of testimony.

17 We adhered to those guidelines. Unless we can receive some

18 type of accommodation to receive additional time within

19 which to evaluate and study what Ms. Carlock is going to

20 testify in addition to, then we will have to claim surprise

21 and, frankly, a failure to accord us due process.

22 COMMISSIONER KJELLANDER: Any response to

23 that?

24 MS. NORDSTROM: Yes. Ms. Hoyd's calculations

25 that set out how Ms. Carlock's calculations were incorrect,

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Wilder, Idaho 83676 STAFF

1 her workpapers were not submitted with her rebuttal

2 testimony and so we need to address that issue now. Idaho

3 Power will have the opportunity to cross-examine

4 Ms. Carlock. Furthermore, they have the opportunity for

5 Sharon Hoyd to respond in her rebuttal testimony and so, in

6 essence, the Company will get the last word on this issue.

7 Furthermore, the exhibits that support the

8 calculations that underlie Ms. Carlock's testimony were

9 provided to the Company yesterday and they have had the

10 evening to review them.

11 COMMISSIONER KJELLANDER: Further response?

12 MR. RIPLEY: Yes. Again, without knowing for

13 certain what Ms. Carlock's additional testimony is going to

14 be, what the contentions of Staff are going to be, we are

15 willing to accommodate Staff providing that the testimony

16 of the rebuttal witnesses, Mr. Gale and Ms. Hoyd, be

17 delayed until tomorrow morning so that we can have an

18 opportunity, hopefully this afternoon, to review whatever

19 Ms. Carlock is going to testify to, to review the exhibits

20 with business hours being available so that other employees

21 are available to assist in that review.

22 I have to caveat that by saying I do not know

23 for certain what Ms. Carlock's testimony is going to be, so

24 I don't know if a day is going to be sufficient. We're

25 hopeful. We want to get this proceeding wrapped up more

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Wilder, Idaho 83676 STAFF

1 than anyone else in this room, but I have to say that we

2 need time within which to study and analyze Ms. Carlock's

3 testimony and I can't in these matters of how complicated

4 they are profess to say that upon the completion of

5 Ms. Carlock's testimony I can launch into meaningful

6 cross-examination, nor do I believe that Ms. Hoyd can hop

7 on the stand and immediately respond to testimony we

8 haven't even heard yet, nor exhibits we just got yesterday

9 afternoon.

10 COMMISSIONER KJELLANDER: Okay. I think what

11 we'll do is we'll allow the testimony to be presented with

12 the clarification questions and then once that's occurred,

13 we'll see where we're at and if there is a request at that

14 time for additional time, we can deal with it appropriately

15 and we'll proceed in that fashion.

16 MS. NORDSTROM: Thank you. Shall I proceed?

17 COMMISSIONER KJELLANDER: Please.

18 MR. RIPLEY: By chance is this Q/A written

19 down?

20 MS. NORDSTROM: Yes, it is.

21 MR. RIPLEY: I wonder if we could receive a

22 copy of the Q/A. It would greatly assist us.

23 COMMISSIONER KJELLANDER: I think that would

24 be very appropriate at this time. Do you have an

25 additional copy or do you need a few moments to --

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Wilder, Idaho 83676 STAFF

1 MS. NORDSTROM: Well, I just need to run to

2 the copier.

3 COMMISSIONER KJELLANDER: Okay, why don't we

4 take a very quick break for that purpose and we'll be right

5 here.

6 MS. NORDSTROM: Thank you.

7 COMMISSIONER KJELLANDER: We'll go off the

8 record.

9 (Pause in proceedings.)

10 COMMISSIONER KJELLANDER: We'll take a

11 15-minute break.

12 (Recess.)

13 COMMISSIONER KJELLANDER: We'll go back on

14 the record. When we left, the additional testimony was

15 being distributed in question and answer format and I also

16 noticed from reading that testimony that there are three

17 potential exhibits, 133 through 135; is that correct?

18 MS. NORDSTROM: That's correct.

19 COMMISSIONER KJELLANDER: And so I guess

20 we'll move now to you and find out what we need to do with

21 those exhibits and how we need to proceed now with

22 Ms. Carlock.

23 MS. NORDSTROM: Okay. I propose that we go

24 ahead and put the testimony on the record and then I'll

25 move for the admission of the exhibits.

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Wilder, Idaho 83676 STAFF

1 COMMISSIONER KJELLANDER: And either without

2 objection or with the same objection?

3 MR. RIPLEY: Well, it puts us in a very

4 difficult position, Mr. Commissioner. First, let me say

5 that upon reading the additional testimony and very quick

6 review of the exhibits, I would first advance the

7 procedural issue that they are irrelevant and immaterial to

8 the decisions that the Commission must decide in this

9 proceeding, i.e., 7 and 11.

10 Setting that aside for the moment and

11 recognizing the rules of evidence are relaxed before the

12 Idaho Commission, we nonetheless still want to say they're

13 irrelevant and immaterial, but moving on to the issue of

14 fairness, we would request that the rebuttal testimony of

15 Mr. Gale and Ms. Hoyd be spread this afternoon, but that

16 cross-examination of Ms. Hoyd and Mr. Gale would occur

17 tomorrow morning after we have had an opportunity to review

18 the additional testimony insofar as comments or exhibits

19 that the Company might submit if it believes that the

20 record is confusing, so if the Commission wants to overrule

21 our objection on relevancy and materiality, then we would

22 request that we be given additional time for this afternoon

23 and this evening to allow Ms. Hoyd and Mr. Gale a

24 reasonable period of time within which to respond to this

25 and in responding to it, that may change our prefiled

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Wilder, Idaho 83676 STAFF

1 rebuttal and so we would ask that we be given until

2 tomorrow morning at which time Mr. Gale and Ms. Hoyd can be

3 presented for cross-examination.

4 COMMISSIONER KJELLANDER: So then as I

5 understand your request, given the assumption that the

6 Commission would overrule the original objection, would you

7 continue with cross-examination of Ms. Carlock this

8 morning?

9 MR. RIPLEY: Yes, we would.

10 COMMISSIONER KJELLANDER: Okay.

11 MR. RIPLEY: Frankly, I'll be quite candid.

12 I do not believe that a two- or three-hour period of time

13 is going to be sufficient for me to cross-examine the

14 technical aspects of what's being presented here and so we

15 would present that, if we desire, through witnesses and

16 through exhibits, so I don't think that would hold up my

17 cross-examination of Ms. Carlock today, but we would want

18 the opportunity to respond to this additional testimony and

19 evidence and we believe the proper way to do that is

20 through witnesses and not through some attempt at

21 cross-examination. That's why we would ask for deferral of

22 Mr. Gale and Ms. Hoyd until tomorrow morning.

23 COMMISSIONER KJELLANDER: And also from a

24 procedural mapping, trying to get through the rest of the

25 hearings that are in front of us with the 16 case, would

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Wilder, Idaho 83676 STAFF

1 the Company be prepared if we were fortunate enough to get

2 that far at a reasonable hour today to begin with the 16

3 case?

4 MR. KLINE: Yes, I'm Bart Kline, I'm Counsel

5 for Idaho Power Company and will be representing the

6 Company in the 16 case. I think we could spread the -- we

7 could certainly spread our direct testimony today, possibly

8 get some of the cross-examination of our witnesses done

9 today. Well, maybe just get it spread and get that done

10 and then the cross would come afterwards.

11 COMMISSIONER KJELLANDER: Why don't we cross

12 that bridge when we get there. It's something to think

13 about and at least then we could perhaps not lose a few

14 hours of the day that might be useful as we head into the

15 weekend, but just give that some thought, if you could.

16 MR. KLINE: All right.

17 COMMISSIONER KJELLANDER: Well, thank you. I

18 believe the Commission probably needs to confer just on the

19 original objection just to make sure we're on the same page

20 and we'll be back with you in just a moment. We'll go off

21 the record.

22 (Off the record discussion.)

23 COMMISSIONER KJELLANDER: We'll go back on

24 the record. The Commission will go ahead and overrule the

25 objection and allow the testimony and once that testimony

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CSB REPORTING CARLOCK
Wilder, Idaho 83676 STAFF

1 is on the record and we get through the cross-examination,

2 we also want to let the Company know that you will have the

3 time that you've requested to review the matter and we'll

4 go forward from there, so at this point, then, we're ready

5 for Deputy Attorney General representing the IPUC Staff to

6 proceed.

7 MS. NORDSTROM: Thank you.

8

9 DIRECT EXAMINATION

10

11 BY MS. NORDSTROM: (Continued)

12 Q Ms. Carlock, did you review the rebuttal

13 testimony filed by Sharon Hoyd?

14 A Yes, I did.

15 Q Do you agree with her calculation of a

16 $15.8 million benefit to Idaho retail customers if only the

17 relevant non-operating transactions at system tie points

18 are used to calculate the average cost?

19 A I don't agree entirely with the methodology

20 for comparing what she has identified as the relevant

21 transactions. The math is correct on Ms. Hoyd's workpaper

22 that shows a $17.3 million total system benefit. This is a

23 corrected number for the $15.8 million Idaho customer

24 number in testimony. Third-party purchases are

25 transactions that may be sales to Idaho Power from IE or

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1 the non-operating system; therefore, this is the most

2 appropriate comparison to make for PCA purposes. This is

3 consistent with Ms. Hoyd's earlier responses to cross.

4 Q What is a system tie point as you understand

5 it?

6 A It is the delivery point at Idaho Power's

7 system border.

8 Q What is your understanding of the

9 classifications used by Ms. Hoyd to identify relevant

10 transactions?

11 A For her calculation of 17.3 million, she

12 identified the relevant transactions as purchases or sales

13 that had delivery points at the system border.

14 Q Using Ms. Hoyd's definitions of relevant

15 transactions, did you arrive at the $17.3 million number

16 shown in her workpapers and identified as $15.8 million on

17 page 7 of her rebuttal testimony?

18 A No. I used the same transactions identified

19 in Idaho Power workpapers as being deliverable at Idaho

20 Power's system border. My calculation of the relevant

21 transactions are shown on Exhibit No. 133. Page 1 shows

22 the sales to Idaho Power in column C through E and compares

23 it to the purchases from third parties in columns F through

24 H since these purchases are transactions that may supply

25 power to Idaho Power. Using the Mid-C index produces

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1 a transfer price that disadvantages customers by

2 $82.3 million for the 2 million megawatt-hours sold to

3 Idaho Power. The comparable purchases from Idaho Power is

4 $12.6 million shown on page 2, column J for a total of

5 $94.9 million or approximately 80.7 million Idaho

6 jurisdictional impact. This comparison shows the Staff's

7 day-ahead system adjustment of 61.5 million or 47 million

8 to Idaho customers based on all transactions is not

9 excessive.

10 Q Does this show that IDACORP traders have

11 consistently beat the market using average cost -- let me

12 rephrase that. Does this show that IDACORP traders have

13 consistently beat the market making the average cost more

14 appropriate than the Mid-C index for power transfers

15 between affiliates?

16 A Traders do not consistently beat the market

17 as explained by witnesses Peseau and Simard. To beat the

18 market, there is either a specific activity that is being

19 completed that is not reflective of the market index prices

20 or there are inappropriate accounting/reporting comparisons

21 being made. These discrepancies can be explained in part

22 by: 1, price differences between transactions at Idaho

23 Power's border and the Mid-C index, including arbitrage

24 transactions and transactions for system balancing

25 requirements, 2, price differences between hourly pricing

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1 and the Mid-C index represented by an average and 3,

2 reporting practices for transfer pricing between affiliates

3 that may be improper.

4 Provided proper safeguards are established

5 and implemented, these discrepancies should be minimal and

6 within a narrow band that will likely be symmetrical around

7 the average. However, until these safeguards are in place,

8 the lower of cost or market for purchases and the higher of

9 cost or market for sales is the appropriate transfer

10 pricing mechanism between the affiliates. This allows IE

11 or the non-operating division to profit from risks actually

12 incurred and still safeguard customers from inappropriate

13 transfer reporting practices between affiliates that may

14 occur.

15 Q Ms. Carlock, were the proper safeguards in

16 place during the 2000-2001 PCA period that would have

17 prevented this discrepancy?

18 A I believe they were not in place.

19 Q Do you have an example of reporting practices

20 for transfer pricing between affiliates that distort the

21 transfer pricing for the PCA calculation?

22 A Yes. During the PCA year, all trading

23 activities were reported on the same book under Idaho

24 Power's name. The transactions were entered at actual cost

25 on the combined book. To separate the operating and

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1 non-operating transactions, affiliate transfers are

2 required. An example of an anomaly in transfer pricing for

3 the PCA currently occurs because not all transactions were

4 reported as non-operating transactions with the operating

5 requirements being removed and priced at the appropriate

6 price. This created a reporting procedure making it appear

7 that the average trading costs were significantly less than

8 the Mid-C market index. More specifically with the

9 day-ahead transactions all activity was classified as

10 non-operating with operating needs being identified and

11 priced separately.

12 The real-time transactions were classified as

13 operating transactions with an adjustment made to remove

14 the non-operating transactions. The reporting problem is

15 that the adjustments were not made at a consistent price.

16 The day-ahead transactions were priced at Mid-C, but the

17 non-operating transfers that would become real-time

18 settlements were removed from the day-ahead levels at the

19 average real-time price for real-time transactions at the

20 system border. The intent behind the transfers is

21 reasonable. However, the reporting procedures for the PCA

22 had the potential to create a mismatch.

23 Q Have you prepared an exhibit to show this

24 mismatch that was created by their reporting procedures?

25 A Yes. I have prepared Exhibit No. 134.

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1 Page 1 shows the November heavy load hours, the Mid-C

2 market index prices per megawatt-hour in column C, the

3 real-time average price per megawatt-hour in column E and

4 the difference per megawatt-hour in column F. Page 2 shows

5 the same comparison for the light load hours. I've also

6 prepared Exhibit No. 135 that reflects the average monthly

7 differences. The average monthly figures show that the

8 transfer price --

9 MR. RIPLEY: Excuse me, could you go a little

10 slower there? I'm trying to follow what you're saying,

11 Terri.

12 THE WITNESS: Okay. Do you want me to go

13 through the exhibits one more time?

14 MR. RIPLEY: Just the 135.

15 THE WITNESS: Okay. I also prepared Exhibit

16 No. 125 [sic] that reflects the average monthly differences

17 during the PCA year.

18 Q BY MS. NORDSTROM: Ms. Carlock, was that 135?

19 A 135.

20 Q Okay.

21 A The average monthly figures show that the

22 transfer difference is not symmetrical and it will not

23 balance itself.

24 Q So if I understand correctly, Exhibit No. 134

25 is just an example of one month and in this case the month

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1 of November?

2 A That's correct.

3 Q Whereas, 135 shows the end result of this

4 discrepancy over a year's period?

5 A Yes. Exhibit No. 134, page 1 shows the heavy

6 load hour differences for the month of November, and page 2

7 shows the light load hour differences for the month of

8 November. Then Exhibit No. 135 shows those average

9 differences per month for each month during the PCA period.

10 Q Is this mismatch something that can be

11 corrected?

12 A I believe that the changes that the Company

13 made in December 2000, along with additional safeguards,

14 can correct this transfer reporting issue going forward. I

15 have not had an opportunity to make this verification, but

16 will do so along with Phase II in the IPC-E-01-16 case.

17 A different pricing mechanism for day-ahead

18 and real-time transactions can be appropriate as the

19 Company has been using once the system activity that these

20 prices will be applied to can be separately identified and

21 priced accordingly.

22 MS. NORDSTROM: Staff would preliminarily

23 move that these exhibits be admitted subject to some

24 objection at a future point by the Company.

25 COMMISSIONER KJELLANDER: So without

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1 objection, at this point we will allow for the admission of

2 those exhibits.

3 MS. NORDSTROM: That's Exhibits 133 --

4 COMMISSIONER KJELLANDER: 133 through 135.

5 MS. NORDSTROM: Thank you.

6 (Staff Exhibit Nos. 133 - 135 were

7 admitted into evidence.)

8 MS. NORDSTROM: At this point in time Staff

9 tenders Ms. Carlock for cross-examination.

10 COMMISSIONER KJELLANDER: We'll move now to

11 Mr. Richardson.

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

13 COMMISSIONER KJELLANDER: No questions from

14 Mr. Richardson. Let's move now to Mr. Ripley from Idaho

15 Power.

16 MR. RIPLEY: Thank you.

17

18 CROSS-EXAMINATION

19

20 BY MR. RIPLEY:

21 Q Ms. Carlock, first, if I could, I would like

22 to establish what the differences are between Staff and

23 Idaho Power Company relative to the $51 million that's the

24 issue in 7/11, okay?

25 A Okay.

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1 Q Now, as I understand it -- I best get a piece

2 of paper here. Can I have just a moment?

3 (Pause in proceedings.)

4 Q BY MR. RIPLEY: Now, in your just recently

5 filed testimony, or whatever it is, you say that the

6 comparison shows the Staff's day-ahead system adjustment or

7 47 million to Idaho customers is not excessive, so we've

8 got, as you would phrase it, approximately 47 million in

9 day-ahead transfer price issues?

10 A That's correct.

11 Q And then we have, as you've stated in your

12 testimony, a jurisdictional number of 4.4 which the Company

13 equates to approximately 3.6 million for real-time

14 transfers?

15 A That's correct.

16 Q And then we've got 8 million that the

17 Commission coined the term and both the Staff and the

18 Company have picked up on it and that's the $8 million

19 November transaction?

20 A That's correct.

21 Q So that would be the three issues, if you

22 will, that ultimately the Commissioners are going to have

23 to decide upon, what to do with the 47 million, what to do

24 with the 3.6 million and what to do with the 8 million.

25 A Yes, and those figures may cause some

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1 confusion because most of the time I speak relative to

2 system numbers because that's all -- that's the way that

3 all of the data is presented. The numbers that you have

4 identified here and I agreed to are Idaho jurisdictional

5 numbers.

6 Q Yes; so when we're going through this

7 proceeding and reviewing and reading this record, you'd

8 have to make sure that you understand that the numbers are

9 comparable so that one party could be talking system and

10 another party could be talking an allocated number and yet,

11 they could be the same and very close as far as the

12 ultimate impact?

13 A That's true.

14 Q Now, first I would like to address the

15 47 million day-ahead transactions, all right? And I want

16 to make sure that you understand that I am not asking you

17 anything about the real-time transactions, only the

18 day-ahead transactions, okay?

19 A Okay.

20 Q Now, your testimony keeps referring to

21 affiliates. Now, during the period of time that we're

22 talking about which ended February 28, 2001, there is no

23 affiliate that is in existence; isn't that true?

24 A From the legal sense, that's true. From a

25 regulatory perspective, an affiliate is any entity that is

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1 not a regulated entity.

2 Q Okay, and that's the position that the Staff

3 is taking is there's no legal distinction or difference

4 between an affiliate and an operating/non-operating

5 function?

6 A For the purposes of this proceeding, that is

7 the position.

8 Q All right. Now, if there were an affiliate

9 in existence, what could the utility do to ensure that its

10 affiliate practices were going to be approved by the

11 Commission in advance of those activities actually

12 occurring? Is there any way that the utility can assure

13 itself that its practices are going to be accepted by the

14 regulatory agency?

15 A I believe that you have done that with the

16 theory. The actual application is where the issue is in

17 this case, so I believe the theories behind your request

18 were approved and I'm not taking issue with those theories

19 provided that the proper safeguards had been implemented.

20 Q Well, you've anticipated my questions and

21 we're going a little bit too rapidly here. Let's go back

22 first to my question that says what could the utility do if

23 it had an affiliate that it wanted to do business with and

24 it wanted to assure itself that the way that it was going

25 to do business with that affiliate was going to be approved

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1 by the Commission? Is there any way for the utility to be

2 assured that the practices it's going to conduct will

3 receive Commission approval in advance of those activities

4 actually occurring, is there any way in your mind you can

5 do that?

6 A I believe that the procedures the Company

7 normally follows will get at that advanced review. Whether

8 you have assurance will depend on the various orders, of

9 course, but in theory, yes, you could get assurance that

10 the overall concept is approved. Now, there's always a

11 question of the application and that's where the review

12 after the fact comes in as to whether those applications

13 were appropriate.

14 Q Well, and I don't mean to argue with you, but

15 I've become confused in your answers. I can get approval

16 in theory but not in practice?

17 A The practice is the area where if there is

18 going to be an affiliate abuse that those abuses will

19 occur. I don't believe the Company intentionally is out

20 there trying to abuse the system and harm ratepayers.

21 Q Well, first I want to talk in the

22 hypothetical or the abstract and not relate the discussion

23 that you and I are having to the particular dispute

24 presently before the Commission. What I'm trying to

25 understand is Staff's position as to whether or not a

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1 utility can receive advance approval for performing

2 transactions with an affiliate and my question is, can that

3 be done, can that be accomplished in Staff's view?

4 A If you want 100 percent assurance, that

5 probably is not possible because of the practical aspects.

6 Q And the practical aspects are, can I get

7 approval to perform certain transactions with the affiliate

8 in advance?

9 A Certain transactions, yes.

10 Q Can I receive approval from the Commission as

11 to how those transactions are to be priced?

12 A Yes. The pricing concepts could be approved

13 if the Commission so desired.

14 Q Now, if the Commission approved the pricing

15 concepts, can they be changed without going back to the

16 Commission?

17 A Now you're getting into this particular case.

18 Q No, I want to maintain it as best I can on a

19 hypothetical level to see what Staff's position is in

20 regard to the op/non-op affiliated transaction theory on a

21 broad base, not on a particular case. We'll get to that,

22 but my questions are simply hypothetical and generic, if

23 you will.

24 A In theory, all approvals require the

25 continuing showing of reasonableness.

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1 Q So under your theory if the affiliate -- if

2 the utility went to the Commission and received approval to

3 price certain transactions, then those transactions are

4 always subject to review by the Staff to see if they

5 shouldn't be changed?

6 A Yes, that's always been the case.

7 Q And so whether the utility has approval to

8 price those transactions at a particular method, it can be

9 changed retroactively?

10 A The reasonableness of those pricing

11 mechanisms is the responsibility of the company no matter

12 what type of a utility the company is and it is that

13 reasonableness that is reviewed after the fact.

14 Q Now, on this review after the fact, does

15 Staff attempt to determine what the market price is for the

16 particular transaction that's under review?

17 A Yes, and that gets into my testimony here,

18 also. The theory behind all reviews for reasonableness

19 that most commissions have used historically and continue

20 to use is looking at cost and market and absent a

21 reasonable showing, many entities use the lower of cost or

22 market for purchases and the higher of cost -- I'm sorry,

23 the higher of cost or market for purchases and the lower of

24 cost or market for sales. The reason that that mechanism

25 is used, whether it's for a service organization, an entity

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1 that produces a product for the utility or in this case

2 power purchases, is to assure that there is not that

3 affiliate manipulation that is possible.

4 Q And when you in this case wanted to use the

5 lower of cost or market, you used the Mid-C as the market?

6 A That is correct.

7 Q So we find ourselves in the strange

8 situation, don't we, that Staff is saying you priced

9 transfers between non-op and op at Mid-C, we don't think

10 that's right, but we will use Mid-C as the market price?

11 A The market price per the contract and what

12 the Company has used and that I agree with is the Mid-C.

13 However, that was conditioned on continued review and the

14 showing that the actual transfers made were properly

15 transferred. It's not necessarily the Mid-C index price

16 that's the issue.

17 Q All right, then let's take a look at your

18 Exhibit No. 114. I believe Exhibit 114 is introduced by

19 you to demonstrate that there was going to be an ongoing

20 review and investigation of the trading practices or the

21 relationship that the Commission had approved between op

22 and non-op; is that correct?

23 A I wouldn't say that was the only reason, but

24 that is one reason.

25 Q One reason, I'll take that. All right, if I

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1 go to the very last page of that exhibit, which is

2 Attachment D, page 56 of 57 and I read at the very top,

3 that's page 56 of 57, Exhibit No. 114, at the very top it

4 says, "Staff" -- fourth line down. "However, Staff is

5 concerned that future basic rates may not properly reflect

6 benefits to the customers for the reduction to the

7 Company's risk, especially with revenue sharing ending."

8 Now, when Staff was using the term "basic

9 rates," were they referring to PCA rates or the basic rates

10 charged by Idaho Power Company?

11 A The basic rates charged by Idaho Power

12 Company.

13 Q Which would not be the PCA rates?

14 A That's correct.

15 Q Now, if we go on down, Staff's Reporting and

16 Records Retention Recommendations, about halfway down, we

17 see the comments of Pete Richardson and Conley Ward speak

18 to this dilemma rather succinctly. Now, Pete Richardson is

19 the attorney that was representing the Idaho Industrial

20 Customers?

21 A That is correct.

22 Q And Conley Ward was the attorney representing

23 Astaris?

24 A That's correct.

25 Q You go on to say, "Staff further recommends

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1 new discussions between the parties be held to discuss

2 risks, rewards, and allocations in basic rates. These

3 discussions should focus on general rates, not the PCA

4 mechanism."

5 Now, is that still the Staff position today?

6 A The Staff position is still that there is a

7 component of basic rates that needs to be reviewed, that is

8 correct.

9 Q But the agreement that was in effect for the

10 pricing of day-ahead transactions between op and non-op was

11 not going to be subject to the review in regard to basic

12 rates, was it?

13 A No, that is subject to the review in the PCA.

14 Q And where would we glean this intention from

15 the orders and the Staff's memos that there was this

16 intention and idea that the method by which the op and

17 non-op transfers for day-ahead were to be priced was going

18 to be subject to review and possible change on a

19 retroactive basis?

20 A You probably would not see it specifically

21 identified and the reason for that is that throughout the

22 workshops and discussions with the Company, I didn't think

23 it was an issue. It seemed very clear to me that that

24 ongoing process was what we were going to continue to

25 follow.

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1 Q It's true, is it not, that since January 1,

2 1999, the Company has used Mid-C index prices to price the

3 transactions between op and non-op?

4 A That is correct.

5 Q And it used it all through 1999 and it used

6 it all through the year 2000?

7 A That is correct, and you see those references

8 in the Staff comments for the PCA case with the caveats as

9 to why that was accepted.

10 Q And Staff's contention is that at any time

11 Staff could come in and say we don't like the way this is

12 going on and we want to reprice it retroactively?

13 A If you're talking from theory, we would be

14 looking at changes that we discussed with the Company and

15 the majority of those would be on a prospective basis if we

16 were making a change to the way the actual pricing

17 terminology was set up. I don't believe I've done that in

18 this case. I have gone in and looked at the transactions

19 that were being transferred and said that that pricing is

20 not appropriately used; therefore, you need to use the

21 lower of cost or market because we cannot break out those

22 distinctions. In fact, as Ms. Hoyd stated yesterday on her

23 cross, the Company can't even break out the transactions

24 that specifically flow through for the power activity.

25 Q And isn't that due to the fact that the

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1 Company was operating under the prior orders of the

2 Commission that you would create a portfolio of resources

3 that would be on the non-op side and when the op side of

4 the business required power that was to be transferred from

5 the non-op side to the op side you would use Mid-C as the

6 market price, isn't that the way the Company conducted its

7 business?

8 A That is the way that the Company presented it

9 and that was accepted for those proceedings by Staff and

10 adopted by the Commission. There is no specific language

11 that says that the Commission specifically adopted that

12 prior to the implementation of IPC-E-00-13.

13 Q Okay. Now, if we could go to page 6 of your

14 prepared testimony and in your answer at the top of that

15 page, and perhaps it would be better to go back to page 5

16 and read the question, it says, "Staff made an adjustment

17 for approximately $51 million associated with the transfer

18 price from the non-system operation to the regulated

19 system. Please explain why."

20 And you say, "The market price is not

21 reflective of a reasonable price surrogate." Why do you

22 use the term "surrogate"?

23 A Because the market price is not the actual

24 price incurred. A review always entails a comparison of

25 market to cost to see that it is reasonable and for -- the

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1 reason that this is not a reasonable surrogate is mainly

2 because of the way that the transfers are conducted. You

3 cannot specifically identify and price without the

4 transfers that Ms. Hoyd was discussing yesterday and

5 explained in Exhibit 30.

6 Q If contrary to your contention that the

7 Commission's orders should be read to say that whenever

8 power is transferred from the non-op side to the op side,

9 the market price will be the Mid-C index, then you'd be

10 wrong?

11 A For the time period after the contract is

12 effective, yes.

13 Q And the only time period we're talking about

14 here is the time period that ended February 28, 2001.

15 A That is correct, and the contract that

16 establishes that procedure that the Commission specifically

17 had language approving that price transfer is in the

18 IPC-E-00-13 case.

19 Q Now we get to that. Why do you contend that

20 it's the position of the Company that it's relying on 00-13

21 for the day-ahead transactions?

22 A I don't want to guess what the Company is

23 contending, but what I am contending and I believe from

24 discussions with the Company previous to this time, I

25 thought we were in agreement, was that the transfers that

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1 were required because of the additional non-system activity

2 required the Company to develop mechanisms to break out

3 operating systems from non-operating systems. Each PCA

4 year we have tried, mostly the Company has continued to

5 try, Staff has been in conversations with them throughout

6 this whole process, to expand on the reliability of those

7 transfers and the identification of the actual transactions

8 that needed to be removed and assure that those included in

9 the PCA were only operating transactions, so prior to

10 IPC-E-00-13, the mechanisms for separating those were

11 reviewed in the PCA reviews, and in each of those instances

12 that both the Company and the Staff refers to, those

13 pricing practices were reviewed for reasonableness within

14 the PCA review time period and the Staff recommended

15 approval of those pricing mechanisms for that PCA period

16 because it remained reasonable and usually it was a better

17 method than what had been done before. This is an

18 evolution, as Ms. Hoyd said, and I agree with that

19 entirely.

20 Q Somewhere in there I think is the answer to

21 my question, but let me ask it again. The Company has

22 since January 1, 1999 priced all day-ahead transactions

23 using the Mid-C index?

24 A Yes, and the Staff reviewed that for

25 reasonableness in each PCA case.

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1 Q Then why do you contend that the Company is

2 relying on 00-13 for the day-ahead transactions using

3 Mid-C?

4 A I contend that they're relying on that for

5 the assurance that it will be priced at that mechanism

6 without a comparison.

7 Q Now, are you confusing the day-ahead

8 transactions with the necessity to do something with the

9 real-time transactions?

10 A No.

11 Q In your mind there's no difference?

12 A There is a difference.

13 Q But as to how the Company was pricing it

14 there is no difference?

15 A The Company was pricing it differently for

16 the two types of transactions.

17 Q And what was the Company relying on in your

18 opinion to price the day-ahead transactions?

19 A The day-ahead transactions were priced at the

20 Mid-C based on prior PCA reviews for reasonableness at that

21 time and the Staff continued to provide the caveat in each

22 of those comments that the Mid-C price index was reasonable

23 for that calculation period. Many times it was due to the

24 narrow band of pricing around the Mid-C index and some of

25 it was due to the lower volumes that were actually

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1 occurring.

2 Q So now we've gotten to the nub of the dispute

3 and that is how to interpret the prior Commission orders as

4 to whether or not Idaho Power Company could rely upon those

5 orders to price its day-ahead transactions based on Mid-C.

6 A That's true, and I believe that the

7 Commission orders accepted the Staff recommendation for the

8 increases or decreases in the PCA cases. They did not

9 specifically address in specific language the pricing

10 mechanism going forward.

11 Q Now, and the comments that the various

12 parties made, including Mr. Ward, Mr. Richardson and Staff,

13 were not related to we want to take a hard look at this, we

14 want to make sure that changes should be made, those were

15 not referring to basic rates but revisions in the PCA rate

16 methodology or procedures, that's how you interpret it?

17 A That's true.

18 Q Now, your theory, then, is because the

19 Company does not have any approval for the day-ahead

20 transactions and since it is an op/non-op situation, you

21 treat it just like you would an affiliate, so, therefore,

22 you say we have to come up with a new price at which to

23 price those transactions because we should not use Mid-C;

24 is that a fair summation of your --

25 A No, I don't believe it is.

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1 Q Okay, tell me what it is, then, because I

2 think it's important that we understand what your thought

3 process was. I assume that you're saying that there was

4 this ongoing process that the Staff could reject the use of

5 Mid-C for pricing day-ahead transactions.

6 A For day-ahead transactions the pricing of the

7 Mid-C was and would continue to be accepted if the

8 reasonableness could be shown.

9 Q Okay, and you're now saying it can't be shown

10 reasonably?

11 A That's correct. I do not believe that

12 reasonableness was shown in this case.

13 Q And what would the Company have to do to

14 demonstrate in your opinion the reasonableness of those

15 transactions?

16 A I believe that showing the actual transfers

17 in a method that is easier to follow would definitely help,

18 showing the safeguards that have been in place to assure

19 that the transactions are being properly made and,

20 therefore, it is appropriate to use the market index for

21 that pricing. That is the biggest hurdle that is left to

22 be dealt with. That is something that we've been dealing

23 with since 1997 and we still have not been able to resolve

24 that. Did that answer all of your question?

25 Q Yes, thank you. Now, there's been some

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1 discussion -- well, let me turn to page 7 of your prepared

2 testimony. In there you're asked to please compare system

3 and non-system term transactions. Do you see that?

4 A Yes.

5 Q And your Exhibit 109 has a listing of the

6 term transactions as to the percent of totals for the

7 system; is that correct?

8 A That's correct.

9 Q How do I read your Exhibit No. 112? Let's

10 just take page 1 of 6.

11 A 112 or 109?

12 Q I'm sorry, I said 109, didn't I?

13 COMMISSIONER KJELLANDER: At first you said

14 109.

15 Q BY MR. RIPLEY: Well, they're generic, so

16 let's use 109 --

17 A Okay.

18 Q -- for purposes of my question. Now, there

19 109 lists the types of transactions, correct, for April

20 day-ahead, real-time, term? Do you see that?

21 A For purchases.

22 Q Yes; so that means that in April of 2000 the

23 system was purchasing term at 11.7642 percent?

24 A From the non-system.

25 Q Now, I'm assuming when you say Idaho Power

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1 system, that's the utility side?

2 A The utility operations.

3 Q Okay; so if I looked at this exhibit, I would

4 see that there have been term purchases.

5 A Those term purchases, many of those are

6 contracts that were in place prior to the PCA year that

7 have not expired.

8 Q But if one wanted to look at your exhibits

9 and say was the utility side of the house entering into

10 term transactions, your exhibit would demonstrate yes,

11 there were term purchases?

12 A In this exhibit the term transactions is not

13 the same in total as the discussion in testimony. Term

14 transactions in testimony refers primarily to the market

15 purchases for hedging purposes as has been discussed

16 previously in this hearing. The term transactions because

17 of the recording mechanisms that Idaho Power has on these

18 exhibits had to include prior contracts that the utility

19 may have entered into even before they were market

20 participants as they are at this point. For instance -- go

21 ahead.

22 Q No, go ahead.

23 A For instance, looking at contracts that may

24 have been, like, five years in nature, there were very few

25 of those that are still in place and some of them have

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1 actually dropped off in the last time period. I have an

2 audit request that has identified, and it's also in the

3 IRP, the Company's IRP, as to what contracts are still in

4 place. Those contracts are still within this term

5 classification and I can pull those out if you want a list

6 of those.

7 Q But looking at the Company and attempting to

8 determine if the Company was purchasing any power, the

9 Company being Idaho Power Company, under term, the Company

10 was?

11 A They were purchasing term transactions of a

12 different nature than what we were talking about

13 previously. The term transactions that include these

14 contracts are ongoing ones. Term transactions that we're

15 talking about for hedging purposes have not been of that

16 long nature.

17 Q I'm asking you if the Company had entered

18 into transactions to purchase power for term during the PCA

19 period under investigation. Whether those contracts

20 started before the PCA year or during the PCA year, there

21 were term purchases?

22 A If I can reclassify your question slightly,

23 the term transactions that were occurring during the PCA

24 year are shown on this exhibit. There were term

25 transactions that were in place for power delivered during

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1 that time period. That is different from entering into

2 term transactions during that time period.

3 Q Now, at the bottom of page 7 you say, "In the

4 past, the Company has purchased large amounts of power at

5 relatively inexpensive prices to serve its load."

6 A I'm sorry, I just got to page 7. Where are

7 you referring to?

8 Q The very last -- lines 24 and 25.

9 A I see that.

10 Q Okay, do you have any documentation for that

11 statement as to what we can test your comment against?

12 A I would say that is more a general statement

13 and specific documentation is based on reviews of Company's

14 workpapers, that type of thing. This statement refers to

15 primarily, and I believe it's probably not real clear here,

16 but the purchases of the power that is required from the

17 market. This large amount doesn't necessarily refer to the

18 total load of the system. I don't know, maybe that's not a

19 confusion. I'm sorry, you're looking confused now and you

20 weren't before. Please reask your question and I will try

21 to respond directly.

22 Q Frankly, I can't. I got your answer and I

23 don't want to pursue it any further.

24 A Okay.

25 Q If I could direct your attention to page 21

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1 and I don't mean to rehash our general discussion, but I

2 would like to ask you specifically that you say commencing

3 at line 15, "When Staff conducted its true-up audit..., it

4 discovered pricing concerns related to the ongoing

5 reasonableness of using the index pricing as a surrogate."

6 And again I would ask you, why do you use the term "index

7 pricing as a surrogate"?

8 A Because the accounting books for the Company

9 in total for Idaho Power are based on cost. The transfers

10 for the separations between operating and non-operating are

11 at the pricing index; therefore, it is a surrogate for the

12 cost that's recorded and actually paid.

13 Q And you're arriving at that conclusion by

14 looking at the non-op side books and seeing what its

15 portfolio of resources cost?

16 A No, I'm drawing that conclusion based on

17 discussions and explanations by the Company in prior audits

18 of the PCA.

19 Q Well, what are the pricing concerns that

20 you're stating on page 21, lines 15 through 19, when you

21 say "pricing concerns," what are those concerns?

22 A The pricing concerns relate to the transfer

23 process that is used to use the Mid-C index for the

24 day-ahead prices.

25 Q Now, if the transfer price based upon prior

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1 Commission orders was considered to be the market price,

2 then your inquiry would end?

3 A No. The pricing of the transfer at the Mid-C

4 would not be questioned provided that the actual

5 transactions to accomplish that transfer were appropriate

6 and documented as being reasonable going forward and for

7 the process reviewed.

8 Q Now, the transactions that you're referring

9 to, I assume, are the transactions for the acquisition of

10 the power by the non-op side?

11 A These transactions are pricing transactions

12 that are the transferring of the actual prices that

13 correspond to activity that's op and non-op. In other

14 words, the total system activity has to be split between

15 the operating side and the non-operating side. It's the

16 process of conducting that split that is the pricing

17 concern for those transactions.

18 Q But in conducting that split, don't we use or

19 didn't the Company use Mid-C prices?

20 A The Company did use Mid-C price for one part

21 of it, that's correct. That's not the contention.

22 Q What is the other contention?

23 A The other contention is that the way that the

24 pricing transfer was conducted is creating inappropriate

25 results; therefore, the pricing can't be accepted in

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1 total. It has not been shown to be reasonable for this

2 time period.

3 Q This same method that you're describing is

4 what the Company conducted since January 1 of 1999; isn't

5 that correct?

6 A The methodology in general is the same.

7 There have been some changes to the way the Company has

8 applied it, adding those transfers, and looking at that

9 difference has created part of the problem. You're looking

10 at the overall reasonableness as another piece of that.

11 Q But the overall reasonableness ultimately

12 comes down to whether or not Mid-C can be used as the index

13 at which you will price these transactions and you're

14 saying I no longer want to use Mid-C?

15 A What it comes down to is has the Mid-C price

16 index been appropriately applied to those transfers and I'm

17 saying that in the overall concept, it has not been

18 properly applied; therefore, we have to look at the total

19 concept and the cost versus market to assure

20 reasonableness.

21 Q And you then go on in your testimony and

22 state while you have disagreements with what occurred in

23 the period that ended February 28, 2001, you believe that

24 that process with some corrections can then be reused

25 again; am I stating your testimony correctly?

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1 A I won't answer yes or no, but I will

2 answer -- basically, that is correct in the nature that

3 you're looking at using the Mid-C index for the pricing.

4 Now, it's those transactions and transfers between the

5 operating and the non-op that create a problem and that

6 doesn't even get into the arbitrage question that Mr. Lord

7 is talking about, which is another phase of that total

8 issue.

9 Q So if I go to page 24 and I look at lines 13

10 through 17, you say, "Staff has repriced the day-ahead

11 power purchased from the non-operating system to the system

12 at the daily weighted average price paid by the non-op

13 system," now it's your testimony we're not looking at what

14 it cost the non-op system to acquire this power?

15 A No, your question was or at least I interpret

16 your question to be is the index price in theory a

17 reasonable application and my answer is yes, with the

18 proper safeguards and the review to show continued

19 reasonableness. This section of my testimony refers to the

20 way that the Staff repriced it because that reasonableness

21 could not be shown.

22 Q But the way that you repriced it is you

23 simply took all of the transactions on the non-op side,

24 added them up and got a price?

25 A That's correct.

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1 Q And whether the sale was to Tuscaloosa,

2 Alabama or anywhere else it didn't matter to Staff, you

3 just added them up?

4 A Some of the transactions were removed because

5 they were obviously flips.

6 Q But a lot of them weren't.

7 A I'm sorry, a lot of them --

8 Q And a lot of them were not. A lot of

9 transactions that possibly you could look at very easily

10 and say this is not a transaction that the non-op side

11 would have ever performed for the op side, you included

12 those in arriving at your cost?

13 A That's right. There were several attempts to

14 try to come up with a more precise method that failed;

15 therefore, we were left with the documentation in

16 workpapers that had all of the transactions and the totals,

17 so we used that as the best information that was available

18 from Company records.

19 Q And that's going along with Staff's theory

20 that since this is an op/non-op transaction and since you

21 believe you've demonstrated that the Mid-C price should not

22 be used that you can, in essence, pretty much arrive at any

23 cost which then the Company is required to rebut; wouldn't

24 that be a fair analysis of your case?

25 A No. I don't believe that you can just come

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1 up with any cost. I believe you have to have a reasonable

2 methodology that follows the information that you have been

3 able to obtain from the Company and I believe the Staff has

4 done that.

5 Q And you believe that's a reasonable

6 methodology?

7 A I believe that's a reasonable methodology and

8 I believe that Exhibit 133, page 1 and page 2, shows that

9 if you removed the transactions that were not touching the

10 system at the system border points you still would have an

11 adjustment. In fact, it would be larger than what the

12 Staff proposed; therefore, in my mind, I concluded that the

13 Staff's original recommendation was reasonable.

14 Q And the 133 and 134, those are the exhibits

15 we received today?

16 A That's correct.

17 Q Does Staff keep changing its computation of

18 reasonableness in this proceeding?

19 A No. The computation shown in 133 and 134 is

20 a showing that from a different methodology following the

21 Company's rebuttal that is another way of showing that the

22 original computation of Staff is still reasonable. I don't

23 propose to change the method. I was just simply showing

24 that under the Company's rebuttal, they claim that the

25 transactions that did not touch the system should be

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1 removed, so I removed those transactions; therefore, the

2 number was greater, but I'm not proposing to change my

3 methodology. It's just showing that it still remains a

4 reasonable number and that including all of the

5 transactions was not to the detriment of the Company like

6 they claimed.

7 Q Now, when I look at the November transaction,

8 is it Staff's position that the $8 million that's involved

9 in this dispute should be disallowed by the Commission

10 because of improper recordkeeping?

11 A That is only partially the reason.

12 Q Is that part of the reason?

13 A I would not say it's the main reason. The

14 main reason is that all indications from the Company

15 records for the board of directors' minutes, the Risk

16 Management Committee minutes and the operating plans with

17 the scenario analysis supports the decision that there be a

18 purchase for the system. That decision was not carried

19 forward, so whether it was an incorrect communication

20 between the RMC committee group and the traders as Ms. Hoyd

21 indicated to us in audit or whether it was a change of

22 decision, the recordkeeping then comes into play that does

23 not support that change of decision, so it is Staff's

24 position that the prudent decision was originally made and

25 that if indeed it was changed that that would be an

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1 imprudent decision and we have adjusted for that

2 accordingly.

3 Q So then it's Staff's position that the

4 Company should have purchased power based upon a belief

5 that the price for power was going to go up?

6 A No. That's not the only characterization

7 that they reviewed at that time. They looked at the

8 precipitation, they looked at the load expectations,

9 Brownlee inflow levels, weather conditions expected. All

10 of those items are built into every operating plan and

11 scenario analysis that the Company conducts and it's that

12 scenario analysis that the Company had available during the

13 time that this decision was made that led me to believe

14 that that was a proper decision and that for the customers

15 we should be reflecting the costs as if that decision had

16 been carried out.

17 Q But doesn't that have to be premised upon the

18 idea that the Company in November should have known that

19 prices were going to go up in January?

20 A I don't think it's totally based on prices.

21 Price is one factor that looking at the price trends from

22 the summer forward and the future prices that that could be

23 a reason that the purchase would be made, but the operating

24 plans itself indicate that there was sufficient reason to

25 buy that power. There was a shortage in January that had

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1 not been covered.

2 Q Well, now, up until mid December, isn't it

3 true that the Company's water flows all indicated that it

4 would be a normal water year?

5 A The indication from the official records

6 appears to be that. There is some indication in the

7 minutes that there was some, and I don't know what the

8 source of this is, but that there was a concern that those

9 records or that that official representation would not be

10 accurate and based on the minute notes that I have, without

11 looking at those minutes, I cannot tell you what the source

12 of that is. I'm sorry.

13 Q And I understand that and I don't want to go

14 too deep into this, Ms. Carlock, but it is true when you're

15 saying that what the Company was looking at, what the

16 records the Company had in existence at the end of November

17 indicated, the official records, the National Weather

18 Forecast Center indicated that water would be normal up

19 until December 15, those were the indications?

20 A There was an expected normal water review

21 indicated in the operating plan and in the minutes, but

22 there was also a note that indicated to me that that

23 expectation was to change.

24 Q And that indeed was probably the ongoing

25 dispute, wouldn't you think, between the various

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1 representatives of Idaho Power Company that made up the

2 Risk Management Committee?

3 A I'm sure that that was one of the disputes.

4 The dispute would be what is water actually going to be,

5 what is the load going to be based on weather conditions.

6 There was an indication that for one meeting weather was

7 expected to be normal. The next meeting weather was

8 expected to be colder, so those are the discussions that

9 the Risk Management Committee would be having as to what

10 they really believed and each one of those members may have

11 a different view, that's correct.

12 Q Now, when we look at the prices, even the

13 prices that you contend should have been utilized if you

14 locked in a purchase at the end of November, those prices

15 were from an historic basis quite high.

16 A If you looked at the price for a particular

17 day, week or forward period compared to an historical

18 period, that would be true for the like period, but the

19 trend in prices indicated that the historical periods

20 probably were not representative of what you could expect

21 for this time period.

22 Q So you believe the Company should have

23 speculated, and I don't mean to use that term in any

24 disparaging way, but the Company should have speculated

25 that prices were going to remain at where they were at the

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1 time they were looking at January prices in November?

2 A During this time period price was one of the

3 considerations that the Company used to calculate its

4 operating plan. It was a criteria that they used and I

5 believe that it's a criteria that they should have been

6 looking at. Now, I don't agree that they were speculating

7 in the term that it's a bad sense for this time period,

8 because you're looking at what the expectations are, and

9 when you believe from all of the evidence before you that

10 there are changes that are going to occur and you can limit

11 the impact of those changes, those would be proper hedges

12 and not speculative transactions that are outside of the

13 duty of a utility.

14 MR. RIPLEY: If I can have just a moment,

15 Mr. Chairman.

16 (Pause in proceedings.)

17 COMMISSIONER KJELLANDER: While we're at

18 ease, why don't we take a break until about 11:00 and we'll

19 resume, so we'll go off the record.

20 (Recess.)

21 COMMISSIONER KJELLANDER: Okay, we'll go back

22 on the record and before we recessed, I believe we were

23 still at the point of cross from Mr. Ripley and so

24 Mr. Ripley.

25 MR. RIPLEY: Thank you. Just a few more,

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1 Ms. Carlock.

2 Q BY MR. RIPLEY: Turning to page 28 of your

3 prefiled testimony, again discussing the November

4 transaction, at page 28 you say, "The operating plans

5 provided to Staff showed that under almost every scenario

6 the system would be short in January." From that is it

7 fair to read that under some scenarios that the system

8 would not be short?

9 A That is correct. Under the high hydro

10 expectations, the system would not be short and there was

11 a -- there was one indication with expected hydro that it

12 wouldn't be short by very much.

13 Q Now, at that time in November the Company was

14 estimating that it was going to be long in the first

15 quarter; isn't that true?

16 A In aggregate, that's correct.

17 Q Now, by "long," I mean there were more --

18 there's more power available than needed to supply the

19 load; would that be a correct assumption?

20 A By long, in general, you're talking about

21 that the load expectations can be met by whatever purpose,

22 that the Company has covered those positions.

23 Q Yes. Why then would it be prudent for the

24 Company to purchase additional power in November taking

25 into account where it believed it was going to be for the

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1 first quarter?

2 A Where it believed it was going to be for the

3 first quarter was talking about all three months and the

4 ability to, for instance, move power by moving water usage

5 from one month to another month. The indications from the

6 minutes provided me and what was going on in the general

7 public arena indicated that there may not be that ability

8 as great as the Company used to have; therefore, it was not

9 obvious from what I reviewed that those long positions from

10 the first quarter in February and March could be used to

11 cover the January purchases.

12 Q And that would be essentially focused around

13 the amount of water that would actually be available?

14 A That would be one large identifying item.

15 Another one would be what was happening with thermal

16 plants, whether there was maintenance periods scheduled,

17 whether there were known outages and if there was an

18 emergency shutdown that had occurred during that time, but

19 for the emergency piece you wouldn't have known that in

20 November.

21 Q But at least until December 15th the

22 Company's official documents were indicating that this

23 would be a normal water year?

24 A There was also an indication that there was a

25 question for that and that there was also a question on the

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1 temperature that went into the operating plans.

2 Q So taking that all into account, it is

3 possible, is it not, that had the Company made the November

4 purchase and events would not have turned out as they did

5 that the Company would have spent more money than it had

6 to, that is possible?

7 A This is possible, but I think all of the

8 evidence would have supported a prudent decision on that

9 review after the fact.

10 Q But doesn't that evidence also demonstrate if

11 you looked at it objectively that the Company's decision

12 not to purchase was prudent?

13 A Depending on what evidence you're looking at,

14 that's true.

15 Q Now, on page 5 -- oh, excuse me, I've got the

16 wrong reference. On page 8, lines 17 through 22, you say,

17 "Term transactions reduce the price variability and

18 usually the cost for that time period." What do you base

19 that statement upon?

20 A I base that statement upon the knowledge of

21 how the Company enters into term transactions. Before the

22 Company will enter into a term transaction, it does

23 analyses and in my view that would be a cost-benefit

24 analysis and a risk analysis that would indicate the pros

25 and cons of entering into a term contract and once those

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1 were evaluated, then the term contracts that are chosen are

2 the ones that reduce the price variability and usually the

3 overall cost for the system.

4 Q Under normal circumstances, wouldn't term

5 purchases be at a price higher than day-to-day purchases?

6 A That's true, but you're looking at the total

7 picture when you're looking at the overall cost and just

8 because the cost of the particular term item is higher, it

9 may actually turn out to be lower than the overall cost at

10 that time period and that's part of the cost-benefit

11 analysis that's conducted.

12 Q Wouldn't that solely be based upon an

13 historical view?

14 A It could be based on historical or

15 prospective. Both of those views are taken into account at

16 the time that you're evaluating these transactions.

17 Q But from a prospective view, are you telling

18 me that normally a term purchase is cheaper than day-to-day

19 purchases?

20 A That depends on the market, but if you're

21 looking at a term purchase for a time period, you will be

22 paying a set price for that term purchase if that is the

23 contract that you enter.

24 Q Yes. Wouldn't you pay a premium for that

25 from the seller?

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1 A You would pay a premium for that if other

2 than for what you were specifically buying. That's where

3 your cost-benefit analysis comes in, is the cost that

4 you're paying for that product reasonable. If you knew you

5 could buy -- when you enter into a term product that is a

6 forward, you are going to be buying power at a future

7 date. No one knows exactly what the price on that future

8 date is, but there are indications as to what people are

9 willing to sell it for now on that date and that is part of

10 the analysis that's conducted and when the Company conducts

11 that analysis, the cost-benefit analysis will show that

12 this is a reasonable course of action for the Company to

13 take and it would document why that is the case.

14 Q I confess to being confused, so let's pick a

15 date so that perhaps we can remove some of the confusion.

16 On November 15th I'm trying to decide what to do on

17 December 15th, 2000, okay?

18 A Okay.

19 Q Are you telling me that on November 15th I

20 can go somewhere and find a price from the day-to-day

21 transactions on December 15th?

22 A You can look at the forward price for

23 December 15th.

24 Q Just for that day?

25 A No, you could look at any time period that

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1 you wanted to.

2 Q But what I'm trying to do is decide which is

3 cheaper on November 15th, a term purchase or a day-ahead

4 purchase cast out into the future, wouldn't the term

5 purchase be more expensive?

6 A The term purchase would be more expensive

7 than the current market. That's why you have to do a full

8 cost-benefit analysis. That price is not the only criteria

9 that you're looking at. In fact, I believe that's the

10 Company's position and maybe I'm not understanding your

11 question. I'm sorry.

12 Q And perhaps we are passing in the night,

13 Ms. Carlock. What I want to do is clear up one final item

14 on your -- well, two final items. First, I think you

15 mentioned in your testimony that the Company had performed

16 hedges during the period in question ending February 28,

17 2001; is that correct?

18 A There are -- the simple answer is yes. I'd

19 have to look at the detail if you wanted to get into that,

20 but there are instances when hedges were entered into.

21 MR. RIPLEY: May I approach the witness?

22 COMMISSIONER KJELLANDER: Yes.

23 (Mr. Ripley approached the witness.)

24 MR. RIPLEY: Just to refresh your memory,

25 Ms. Carlock, I just have one question.

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1 A I'm sorry, I don't have enough information on

2 this sheet to know exactly what I'm looking at.

3 Q BY MR. RIPLEY: Well, let me just ask

4 you this: During the period in question that ended

5 February 28, 2001, the Company did enter into hedges for

6 that period of time?

7 A Yes, there were hedges that occurred for -- I

8 believe there was a hedge that had power delivered in

9 December, if my memory serves me right, and I know there

10 were a couple others. I'd have to look at the Risk

11 Management Committee minutes and the actual transactions to

12 determine which ones.

13 Q And the sole purpose of my question is if

14 someone were to contend that the Company did not enter into

15 any hedges for the period ended February 28, 2001 for the

16 PCA period under advisement, the answer would be yes, they

17 did enter into some hedges?

18 A I don't believe I contended that there were

19 no hedges entered into.

20 Q I understand that.

21 A My statement was basically that there were

22 limited hedges that was different from prior time periods.

23 Q Okay. Now, one final little area. First,

24 when you say that the Company -- well, first let me ask you

25 this: Did the Company change its methods of reporting or

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1 recording from January 1, 1999 through February 28, 2001

2 for its day-ahead transactions?

3 A Some of the workpapers that I saw showing

4 those transactions showed the actual activity in a

5 different fashion, so I can't say that that's an actual

6 change in the ultimate reporting, but the workpapers I

7 reviewed did have some changes on it.

8 Q Now, in your additional rebuttal, you state

9 that -- let me see if I can get this. You were asked by

10 your counsel that with proper safeguards, could the Company

11 continue to do that which it did during the existing PCA

12 period as far as using Mid-C and pricing real-time

13 transactions; is that a correct paraphrasing of your answer

14 to counsel's question?

15 A I don't think it is. Which page are you

16 referring to?

17 Q That's the unfortunate part. This was a live

18 question that your counsel asked you and said with proper

19 safeguards in place, could the Company continue to use

20 Mid-C, et cetera, do you recall that?

21 A Oh, I do recall that question, yes.

22 Q Perhaps it would be useful, and I apologize,

23 but perhaps it would be useful for you to restate what your

24 response to those proper safeguards was and what the

25 Company could or could not do and then I can ask my

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1 question so we're not passing in the night.

2 A I believe that my response to that question

3 was focused primarily on the possibility of using pricing

4 mechanisms going forward if pricing safeguards were in

5 place, and my response was that with proper safeguards such

6 as those that we're going to be looking at in the 16 case

7 that the transfers that are occurring between the Company

8 should be able to be priced at the market price because

9 those transfers would not be occurring in the same fashion.

10 Q And the market price would be, again, using

11 the Mid-C index?

12 A The market price would be using the Mid-C

13 index for the day-ahead.

14 Q Okay.

15 A And in actuality, that's the largest portion

16 of all of the transactions between the entities.

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

18 have.

19 COMMISSIONER KJELLANDER: Thank you,

20 Mr. Ripley. Let's move now to questions from the

21 Commission. Commissioner Hansen has one.

22

23

24

25

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CSB REPORTING CARLOCK (X)
Wilder, Idaho 83676 STAFF

1 EXAMINATION

2

3 BY COMMISSIONER HANSEN:

4 Q Terri, just to summarize just a couple of

5 things so I'm sure I got what you said, are you saying what

6 is wrong is not the Mid-C index, but Idaho Power's conduct

7 in deciding when and how to trade between the operation and

8 the non-operational books; is that what you're saying?

9 A That's the biggest portion of it. There were

10 three items that I listed that go into that. One is the

11 difference in the Mid-C transactions of being able to

12 purchase at the border prices. The second one is the

13 hourly difference between Mid-C prices and the Mid-C index

14 and I'm not really concerned about that one because it

15 typically is symmetrical, and the third one is that

16 reporting and the transfer pricing between the affiliates

17 and it's that piece of it as to how you identify exactly

18 what is the non-operating versus the operating transactions

19 to apply the transfer price to.

20 Now, if you knew that the amounts purchased

21 from the affiliate in megawatt-hours were not being changed

22 by transfers and you had the proper safeguards in place

23 that we've been discussing with the Company in 16, then I

24 would say that the market price would be the appropriate

25 surrogate price for these transactions and that's absent,

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CSB REPORTING CARLOCK (Com)
Wilder, Idaho 83676 STAFF

1 you know, any discussions of the arbitrage that can take

2 place, that type of thing.

3 Q On page 6, lines 3 and 4, and I think you

4 were just discussing basically that, but are you saying

5 that the main problem is that the transfer price between

6 affiliates must be shown to be reasonable and it's not, but

7 with the proper safeguards it could be; is that right?

8 A Yes, and as an overall concept that might

9 help you is that in general, a market is going to fluctuate

10 around an average. That average is going to be the index

11 and to show that that continues to be reasonable, you have

12 to compare items to that price, that index price, and if

13 they're within a reasonable band and you have carried out

14 the proper documentation, then there should be no problem

15 at all and that's what I'm saying, but that must be proven

16 as you go forward in reviewing the transactions.

17 COMMISSIONER HANSEN: That's all I have,

18 Mr. Chairman.

19 COMMISSIONER KJELLANDER: Commissioner Smith.

20 COMMISSIONER SMITH: Just one, Terri.

21

22

23

24

25

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CSB REPORTING CARLOCK (Com)
Wilder, Idaho 83676 STAFF

1 EXAMINATION

2

3 BY COMMISSIONER SMITH:

4 Q I guess Mr. Ripley asked you several

5 questions trying to buy power on November 15th for

6 December 15th and what would be higher and what's normal

7 and my question is if we're talking historically, say

8 January of '97 to April of 2000, we probably could have

9 ringed in a set of circumstances that we would call normal?

10 A During that time period prices were within a

11 very narrow band compared to what you've seen after that

12 time period.

13 Q Yes, and if you're looking at May of 2000 to

14 May of 2001, is there any way of determining what's normal?

15 A I think there were a lot of changes occurring

16 in the electricity market and the industry as a whole that

17 there was very little that was normal.

18 COMMISSIONER SMITH: Thank you.

19 COMMISSIONER KJELLANDER: Let's move now to

20 redirect.

21

22

23

24

25

410

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Wilder, Idaho 83676 STAFF

1 REDIRECT EXAMINATION

2

3 BY MS. NORDSTROM:

4 Q Ms. Carlock, just to clarify, you're saying

5 that the Mid-C pricing index at some point could be

6 appropriate; correct?

7 A Yes. I've always held the contention that

8 with proper safeguards when you have operating and

9 non-operating transactions that an index price is easier to

10 monitor than going through all of the transactions, so I

11 believe that that is a possibility going forward and I

12 would hope that that is the outcome of the 16 case.

13 Q And would that also include bookkeeping that

14 properly reflects the transfer prices?

15 A That's correct.

16 Q I believe when you were speaking earlier

17 about lower cost or market or higher cost or market for

18 purchases and sales, I think you said it one way and then

19 stated it differently another time, can you state the

20 correct terminology for purchases and sales?

21 A Yes, there was one time when I did misstate

22 that. The correct terminology is to use the higher of cost

23 or -- you would use the higher of cost or market for

24 sales. You would use the lower of cost or market for

25 purchases.

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CSB REPORTING CARLOCK (Di)
Wilder, Idaho 83676 STAFF

1 Q Okay, thank you. Isn't it proper for the

2 Staff to identify improper application of a pricing

3 mechanism in one PCA period that was not evident to general

4 acceptance by the Commission in a prior PCA period?

5 A Let me just --

6 Q Maybe I didn't say that very well.

7 A What happens is that in one PCA period a

8 review of the transactions and the appropriateness is

9 made. That may have limited circumstances that will change

10 in another PCA period, so what is approved at one point for

11 reasonableness may look differently at another point just

12 because the way the transactions are transferred.

13 Q So we had talked about the fact that the

14 Mid-C has been used since 1999.

15 A That's correct, for day-ahead transaction

16 transfers.

17 Q Right. Were you aware of the accounting

18 practices that you discussed in your additional direct

19 testimony today back in 1999?

20 A Was I aware of the concerns that I had at

21 that point or I'm not sure what your question is.

22 Q Well, in your additional direct testimony

23 today you talked about the fact that transactions were

24 booked in at one price and then removed from the combined

25 book at another price and that created a discrepancy. Were

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CSB REPORTING CARLOCK (Di)
Wilder, Idaho 83676 STAFF

1 you aware that that was happening back in 1999?

2 A It was not apparent in prior PCAs if that was

3 the practice and that may have been because of the narrow

4 band of the market price and the transfer prices. It's

5 apparent, for instance, in the November example that I

6 showed in Exhibit 133 through 135 how those changes have

7 been -- actually, the results are shown in those exhibits

8 and it picks up that differential in pricing.

9 Q So this may have been happening since 1999,

10 but no one picked up on it because there wasn't price

11 volatility until just recently?

12 A It may have been the same overall process and

13 from Mr. Ripley's questions, I would imply that that

14 probably is the case, but because of the narrow band of the

15 Mid-C index and the narrow band for the costs that were

16 incurred, it was not apparent because everything appeared

17 to be reasonable in that comparison review, and part of the

18 reason that it was picked up this time is because of the

19 large fluctuations in the Mid-C index price.

20 Q So if it had produced an unreasonable result

21 in those past PCAs, Staff would have objected to it, too,

22 then?

23 A Yes.

24 Q In regards to the November transaction,

25 Mr. Ripley asked you what you had reviewed in coming up

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CSB REPORTING CARLOCK (Di)
Wilder, Idaho 83676 STAFF

1 with your recommendation that that approximately $8 million

2 be disallowed. You said that you reviewed operating

3 transactions and the like. Did you review the Company's

4 credit limits?

5 A That was part of the Risk Management

6 Committee review and in those minutes the credit limits

7 were discussed at various times for the total operations,

8 and as Mr. Anderson indicated yesterday, the Company

9 doesn't have specific guidelines for the utility

10 operations, so this would be in total that they would be

11 reviewing those.

12 Q Do you think that credit limits had any

13 affect on the decision making for this particular

14 transaction in November?

15 A You're talking about credit limits as far as

16 the stop loss limits that the Company has established in

17 their risk management policy, I'm assuming, rather than

18 some financing credit limit. Let me answer the question in

19 that way. Provided that -- as far as the credit limits

20 from the stop loss provisions under the Company's risk

21 management, those concerns are addressed at the Risk

22 Management Committee meetings and I reviewed the minutes

23 discussing those concerns and as part of that, there were

24 discussions at various time periods throughout the PCA

25 period where these limits were actually near the limit or

414

CSB REPORTING CARLOCK (Di)
Wilder, Idaho 83676 STAFF

1 actually exceeding the limit and the Risk Management

2 Committee was changing maybe the way the transaction that

3 was occurring on the non-operating side in total or

4 changing the limits. There were instances where those

5 credit limits were increased. In fact, in November, I

6 believe it was, the VAR limit was doubled.

7 Q And when you say "VAR," what does that mean?

8 A Value at risk and that's a measure as to how

9 much risk the Company is undertaking and what the

10 fluctuations could be when they price those transactions

11 and market to market for reporting purposes.

12 Q So could the Company have placed the

13 transaction in November to hedge in January of 2001 and

14 still be within their limits?

15 A I don't know. It would depend on the

16 timing. There was a limit increase about that time, so

17 they could have. Prior to the November 21st meeting, they

18 may not have been able to. I don't know how close they

19 were to those limits. I didn't have all that detail.

20 Q In giving your recommendation, you also

21 stated that you reviewed policies and procedures governing

22 risk management for Idaho Power. Was that for the

23 regulated entity or for the deregulated entity?

24 A The policies were the combined policies. I

25 did not review the specific credit or the stop loss limits

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CSB REPORTING CARLOCK (Di)
Wilder, Idaho 83676 STAFF

1 that they have established for the non-operating side. We

2 discussed them in general, but the response to audit

3 requests that we accepted was basically just the general

4 discussion that they had them for the non-operating side,

5 planned to develop them for the operating side, but we did

6 not go through all of those in detail and when I

7 specifically asked for VAR and CVAR limits, which are stop

8 loss limits that the Company has imposed, then those

9 measures were not reviewed. There was only points in time

10 that the Company directed me to public documents that

11 indicated those items for a point in time.

12 Q Now, you mentioned CVAR, what is that?

13 A Credit value at risk, I believe.

14 Q And again is a stop loss?

15 A It's a measurement -- it's not a stop loss.

16 It's a measurement for the level of risk that is being

17 undertaken by the entity. A stop loss is a cap and that is

18 what the Company uses. These other measures are measures

19 that actually give an indication as to that variability.

20 Q Mr. Ripley indicated during cross related to

21 this November transaction that Staff believes price

22 speculation should be part of the Company's analysis. Do

23 you agree with that statement?

24 A Would you restate that, please?

25 Q It was my understanding that he indicated

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CSB REPORTING CARLOCK (Di)
Wilder, Idaho 83676 STAFF

1 that Staff believes price speculation should be part of the

2 Company's analysis, that that was Staff's opinion. Do you

3 agree with that characterization?

4 A My impression of his question was that Staff

5 believed that price should be a part of the calculation.

6 Now, I don't believe that price speculation in the sense

7 that it is a risky speculation should be part of that, but

8 I believe that price is an item that needs to be

9 considered. In fact, the Company did consider that price

10 when it was looking at the historical trends and by looking

11 at those historical trends compared to where they are now

12 and where they may be in the future for price risk is a

13 form of speculation. The Company essentially speculated

14 the price was not at a reasonable level, therefore, they

15 made the decisions accordingly. That is an equal

16 possibility as to, you know, going forward whether price

17 would go up or whether price would go down.

18 Q But you're saying that price is just one

19 factor of many; is that fair?

20 A Price is one factor of many. In fact, when

21 you're looking at the operating reports, the actual

22 operations of the system are the most important aspects of

23 the review and if you need power and it appears that power

24 prices have been high and are going to continue to be high,

25 then as a utility I believe that that would be a prudent

417

CSB REPORTING CARLOCK (Di)
Wilder, Idaho 83676 STAFF

1 decision to try to minimize the impact of increased

2 prices. Usually in these markets the upside potential is

3 significantly greater than the downside potential.

4 Q Okay. Mr. Ripley had you answer some

5 questions in regards to page 28 when he was talking about

6 the planning scenarios that were reviewed by the Risk

7 Management Committee, and you said that under a couple of

8 scenarios the Company had adequate power available; is that

9 correct?

10 A Yes, that if you looked at the scenario

11 analysis that was presented to me in support of --

12 actually, it was part of the support for the Risk

13 Management Committee minutes, the information that they

14 were looking at in part showed that under the one scenario

15 analysis where you had higher than normal expected water

16 conditions, the Company would not be short in January.

17 Q So it was only under the most abundant water

18 conditions that the Company was going to have adequate

19 power?

20 A Not necessarily. It depends on how you

21 combine all of those transactions together and the

22 information that was retained by the Company to show what

23 its decision was based on indicated that under almost all

24 instances there would be a shortage, so whether they should

25 cover that shortage or not is what Mr. Ripley was talking

418

CSB REPORTING CARLOCK (Di)
Wilder, Idaho 83676 STAFF

1 about.

2 Q So some of those scenarios weren't relevant

3 to the circumstances that were presented to the Company?

4 A If I was looking at that data now or I should

5 say on November 21st if you were looking at the operating

6 plan and the scenario analysis that showed high water

7 conditions, that would probably not be the scenario

8 analysis that you would be focusing on. You would either

9 be focusing on the scenario analysis that would have water

10 at normal or low water and then you would have to look at

11 all of the other conditions for precipitation, weather,

12 that type of thing that would continue to change which view

13 you looked at.

14 Q Can you just restate, I know we kind of

15 danced around the issues earlier on cross, but why it was

16 prudent for the Company to have completed that transaction

17 in November for the additional power in January 2001?

18 A I believe it was prudent for them to complete

19 it based on the Risk Management Committee minutes that

20 approved that purchase. The indication from all of the

21 documentation that I reviewed supported that original

22 decision. Now, there are other factors that they would

23 have considered and the Company witnesses have discussed

24 some of those, but the indications from the scenario

25 analysis support that decision and I believe it was prudent

419

CSB REPORTING CARLOCK (Di)
Wilder, Idaho 83676 STAFF

1 for that decision to have been made.

2 MS. NORDSTROM: Thank you. No further

3 questions.

4 COMMISSIONER KJELLANDER: Thank you,

5 Ms. Carlock.

6 (The witness left the stand.)

7 COMMISSIONER KJELLANDER: Let's see, we're

8 about 20 minutes before noon. Why don't we go ahead and

9 get started with the next witness if for no other reason

10 just to get the testimony spread and then to prep them for

11 the cross-examination and then perhaps at that point we

12 could break for lunch, so if would call your next witness.

13 MS. NORDSTROM: Okay, thank you. Staff would

14 Tom Lord.

15

16 THOMAS J. LORD,

17 produced as a witness at the instance of the Staff, having

18 been first duly sworn, was examined and testified as

19 follows:

20

21 DIRECT EXAMINATION

22

23 BY MS. NORDSTROM:

24 Q Good morning.

25 A Good morning.

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CSB REPORTING LORD (Di)
Wilder, Idaho 83676 Staff

1 COMMISSIONER KJELLANDER: You may need to get

2 closer to the microphone.

3 Q BY MS. NORDSTROM: Please state your name and

4 spell your last name for the record.

5 A Thomas J. Lord, L-o-r-d.

6 Q By whom are you employed and in what

7 capacity?

8 A I'm employed by Teknecon Energy Risk

9 Advisers, LLC. My capacity is as a principal and partner

10 in the firm.

11 Q Are you the same Tom Lord that filed direct

12 testimony on July 20th and prepared Exhibit No. 107?

13 A I believe that is the exhibit number and yes,

14 I did.

15 Q Do you have any corrections or changes to

16 your testimony or exhibit?

17 A I believe there was one change that was filed

18 later for specific changes due to change in wording.

19 MS. NORDSTROM: And I do believe that was

20 prefiled already. Do you want me to go into detail on

21 that?

22 COMMISSIONER KJELLANDER: Only if there is an

23 objection or request for clarification.

24 MR. RIPLEY: Well, we haven't got to the

25 spreading of the testimony.

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CSB REPORTING LORD (Di)
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1 THE WITNESS: But there was on July 24th an

2 amendment filed to my testimony. I just wanted to make

3 sure that was accepted.

4 MR. RIPLEY: Oh, absolutely. We recognize we

5 received that.

6 THE WITNESS: Thank you. I just wanted to

7 make sure that one was covered.

8 COMMISSIONER KJELLANDER: Just for

9 clarification for the Commission, that is in our books; is

10 that correct? I'm looking to anyone who will nod

11 appropriately.

12 MS. NORDSTROM: Yes.

13 COMMISSIONER KJELLANDER: Could you tell us

14 what page numbers?

15 THE WITNESS: It was also with the exhibits

16 of Terri Carlock, that same filing.

17 MS. NORDSTROM: What page number was that,

18 Tom?

19 THE WITNESS: They were pages 3 and 6,

20 revised 7-24-01.

21 MS. NORDSTROM: Okay, thank you.

22 COMMISSIONER KJELLANDER: We do have that.

23 Thank you very much.

24 Q BY MS. NORDSTROM: If I were to ask you the

25 questions set out in your prefiled testimony, would your

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CSB REPORTING LORD (Di)
Wilder, Idaho 83676 Staff

1 answers be the same today?

2 A As far as questions asked, yes.

3 MS. NORDSTROM: I would move that portions of

4 the prefiled direct testimony of Tom Lord be spread upon

5 the record as if read and Exhibit 107 be marked for

6 identification. Specifically, I would ask the following

7 sections be spread upon the record: page 1, line 1 through

8 page 9 line 6; page 11, line 17 --

9 COMMISSIONER HANSEN: Page 9, what was the

10 line?

11 MS. NORDSTROM: Line 6.

12 COMMISSIONER KJELLANDER: As you request

13 this, could you kind of give us a heads up? Is this in

14 reference to any material that may be specific only to

15 another case?

16 MS. NORDSTROM: The portions that we're

17 taking out of his testimony refer to the prospective 16

18 case and so the testimony that we're asking be spread upon

19 the record focuses only on the issues in 7/11 and we had

20 already filed these specific page numbers with the Company

21 as part of a production response.

22 COMMISSIONER KJELLANDER: So this is in

23 anticipation of an objection?

24 MS. NORDSTROM: Well, that and in

25 anticipation of the issue that we're trying to keep the

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CSB REPORTING LORD (Di)
Wilder, Idaho 83676 Staff

1 record separate.

2 COMMISSIONER KJELLANDER: Okay, thank you, so

3 now I'm ready to follow.

4 MS. NORDSTROM: Okay, that was page 1 through

5 page 9, line 6; page 11 --

6 COMMISSIONER KJELLANDER: Page --

7 MS. NORDSTROM: -- 11.

8 COMMISSIONER KJELLANDER: Let's back up.

9 Page 1, line 1 through what?

10 MS. NORDSTROM: Through page 9, line 6.

11 COMMISSIONER KJELLANDER: Thank you.

12 MS. NORDSTROM: Page 11, line 17 through

13 page 15, line 22; page 17, line 18 through page 31, line 7;

14 and finally, page 33, line 14 through page 34, line 20.

15 That being said, I tender the witness for

16 cross-examination.

17 COMMISSIONER KJELLANDER: First and foremost,

18 are there any objections to spreading those portions of the

19 prefiled testimony and the exhibit?

20 MR. RIPLEY: I would say that I have a

21 conditional objection, for lack of a better term, which I

22 think I can explain very quickly to the Commission. If one

23 would go to page 11, line 17 of Mr. Lord's testimony, the

24 question is asked in IPC-E-01-7 and 11 what is your

25 understanding of the relationship between IES and Idaho

424

CSB REPORTING LORD (Di)
Wilder, Idaho 83676 Staff

1 Power, and then there is a discussion concerning the

2 agreement that has been entered into. This particular

3 testimony as it is drafted is simply not relevant to the

4 issues that the Commission must decide in 7 and 11 and that

5 kind of goes to my overall objection as to Mr. Lord's

6 testimony.

7 It is indeed germane to 16 and it's easy for

8 me to say that, I pass it on to Mr. Kline, but I don't mean

9 to do it that way, I mean to say that Mr. Lord's testimony

10 has very little relevance, if any, to the issues that the

11 Commission must decide in 7 and 11. It is jumbled

12 together, which I believe is unfortunate, but we didn't

13 create that and to try to unjumble it is extremely

14 difficult in regard to Mr. Lord's testimony, so I guess we

15 have to object on the grounds that there is a mixing and a

16 matching of testimony that we believe is not pertinent to 7

17 and 11 and we would object to the spreading of Mr. Lord's

18 testimony on the grounds of relevancy and materiality to 7

19 and 11.

20 COMMISSIONER KJELLANDER: Any response?

21 MS. NORDSTROM: Mr. Lord's testimony focuses

22 on what was in place and what was not in place which

23 certainly impacts the 7/11 case before the Commission right

24 now. Obviously, problems that need to be resolved in 16

25 focus on things that weren't in place during 7/11 and

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CSB REPORTING LORD (Di)
Wilder, Idaho 83676 Staff

1 issues that affect 7/11 which includes transmission and

2 wheeling, transfer pricing, what safeguards were in effect,

3 what safeguards weren't in effect. All of those impact

4 7/11.

5 Moreover, we've attempted to separate out the

6 sections that deal solely with 16. We've made a good faith

7 effort in that and his testimony is pertinent and germane

8 to the Commission's decision in this matter. If it's just

9 an issue of materiality or relevancy, that's certainly

10 something that the Commission can take into account when

11 it's making its deliberations. If it's something that the

12 Commission believes is appropriate for 16, it will

13 disregard that section, but as it's been separated out and

14 in the manner in which I am attempting to spread it on the

15 record, this testimony does impact 7/11 to the best of my

16 knowledge.

17 COMMISSIONER KJELLANDER: Thank you. We're

18 going to overrule the objection and spread the testimony as

19 has been outlined by the Deputy Attorney General

20 representing Staff as far as the language only being spread

21 that is at least at this point perceived relevant in

22 relationship to the 7/11 case and also the exhibit that was

23 referenced and there was just one exhibit; is that

24 correct?

25 MS. NORDSTROM: Correct, Exhibit 107.

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CSB REPORTING LORD (Di)
Wilder, Idaho 83676 Staff

1 (The following prefiled testimony of

2 Mr. Thomas Lord is spread upon the record.)

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11

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15

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427

CSB REPORTING LORD (Di)
Wilder, Idaho 83676 Staff

1 Q Please state your name, by whom you are

2 employed and business address.

3 A My name is Thomas J. Lord. I am employed by

4 Teknecon Energy Risk Advisors, LLC (TERA). My business

5 address is 1515 South Capital of Texas Highway, Austin,

6 Texas 78746.

7 Q What position do you hold with TERA?

8 A I hold the position of Partner.

9 Q Please describe your experience relevant to

10 this testimony?

11 A I have been involved, as a both consultant

12 and employee, in the development and deployment of energy

13 risk management systems. This experience includes direct

14 responsibility for assessing, transacting, and managing

15 speculative energy positions utilizing both physical and

16 financial transactions. It also includes guidance for the

17 creation of "best practice" risk policies, procedures

18 and processes for investor-owned utilities and major

19 consumers of electricity. An additional description of

20 my industry experience and educational qualifications is

21 attached.

22 Q What is the purpose of your testimony?

23 A The purpose of my testimony is to discuss the

24 requisite internal skills necessary for Idaho Power

25 Company (IPC) to assure price risk management

428

IPC-E-01-7/11/16 LORD, T. (Di) 1
07/20/01 TERA

1 capabilities for its customers, potential mitigation of

2 speculative risks for Idaho Power affiliates due to

3 contractual relationships with Idaho Power and

4 recommended actions to assure Idaho Power receives

5 appropriate value and rewards from its affiliate

6 relationships whenever Idaho Power receives transactional

7 assistance or provides internal demand and supply

8 information.

9 Q Please summarize the scope of your testimony.

10 A I will testify as to my understanding of Idaho

11 Power's ability to manage forward hedging of wholesale

12 energy price risks. I will also testify as to my

13 understanding of certain past practices and transactional

14 patterns that have created or may have created value for

15 Idaho Power affiliates without appropriate compensation

16 to the regulated customers. Finally, I will recommend

17 changes that Idaho Power should adopt to both contractual

18 relationships with affiliates and internal practices that

19 will improve business processes and risk/reward

20 allocation between Idaho Power and its affiliates.

21 Q IPC testimony (Gale prefiled direct testimony

22 Case No. IPC-E-01-16, pg 4, line 12) indicates that long-

23 term (time periods beyond 30 days in the future) hedging

24 activities may not be performed by IPC in the future. In

25 your opinion, is hedging an appropriate activity for a

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IPC-E-01-7/11/16 LORD, T. (Di) 2
07/20/01 TERA

1 regulated utility to pursue on behalf of its customers to

2 prudently manage the supply of energy to its customers?

3 A Regulated utility customers implicitly depend

4 upon the utility provider to make decisions to manage the

5 cost of energy for their consumption. Wholesale energy

6 market price fluctuations, due to internal supply excesses

7 or shortfalls, make the risk of price changes for energy

8 purchases or sales on behalf of the customers significant

9 to individual customers. While hedging decisions are

10 dependent upon a variety of considerations, the failure to

11 make those decisions implicitly exposes the utility

12 consumer to the equivalent of unmanaged speculation.

13 My opinion, therefore, is that a utility must

14 possess the capabilities to determine whether the risk

15 exposure of its customers to future price movements is, in

16 the utility's best opinion, acceptable. The complete

17 reliance upon spot pricing for open market transactions

18 is, implicitly, a speculative decision to accept complete

19 exposure to wholesale market price volatility. Only when

20 a regulated utility has responsibly implemented the

21 internal systems necessary to make and execute hedging,

22 or price risk management determinations on behalf of its

23 customers, can it remove this implicit speculative risk.

24 Q Why isn't the power cost adjustment an

25 effective hedge against price movement?

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IPC-E-01-7/11/16 LORD, T. (Di) 3
07/20/01 TERA

1 A A power cost adjustment ("PCA") mechanism only

2 acts to moderate the rate of change of customer prices by

3 averaging price movements from one year and applying them

4 to the next year's customer rates. It does not, however,

5 remove the risk of adverse price movements. Over time

6 the PCA guarantees the customer will pay average cost of

7 the market prices. The PCA does not remove customer

8 exposure to systemic adverse price movements that are

9 created by the variable nature of customer energy

10 consumption patterns. Therefore, the PCA is not an

11 effective hedging mechanism.

12 Q What is an effective method of reducing

13 customer exposure to price movements?

14 A The only method of reducing customer exposure

15 to wholesale price movements is to secure a source of

16 energy which possesses, in some manner, an element of

17 certainty concerning the price of the energy at time of

18 delivery. In contrast, purchasing at "market price" at

19 the time of delivery assures that the energy consumer

20 will be a price taker at the time of purchase. In any

21 wholesale market, a price taker is fully exposed to the

22 ability of suppliers to extract value from the production

23 of the good. In electricity, the wholesale market is

24 perceived as inefficient and subject to the ability of

25 suppliers to extract significant economic value for

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IPC-E-01-7/11/16 LORD, T. (Di) 4
07/20/01 TERA

1 prompt delivery of energy.

2 It is possible that price risk management

3 activities may result in higher consumer energy costs

4 than relying on spot price purchases for all wholesale

5 energy needs. However, the risk of unmoderated price

6 movements and subsequent abrupt changes in annual prices

7 may be unacceptable to many or all customers.

8 Previously, I discussed the implicit

9 speculation accepted by the decision not to implement

10 price risk management decisions. The possibility of

11 resultant higher energy prices is the risk accepted from

12 the reward of a smaller range of potential pricing

13 outcomes that results from hedging activities. It is

14 this reduction in the range of potential outcomes that

15 reduces the risk of the utility consumer.

16 Therefore, I believe that captive customers

17 should be provided some mechanism by which the customers

18 can opt to be protected from wholesale market price

19 volatility. Price risk management, or hedging, is the

20 logical method of providing that mechanism.

21 Historically, regulated utility customers have

22 depended upon their service provider and regulators to

23 insulate them from wholesale energy markets, either by

24 making long-term market purchases or by constructing

25 generation assets. In the evolving deregulated wholesale

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1 energy markets, the forward energy prices will be the

2 factor that determines the advisability of the "build

3 versus buy" decision. The ability to analyze forward

4 market prices and make the correct "build versus buy"

5 decision is a fundamental component of the capability to

6 provide price risk management services to regulated utility

7 customers.

8 Q What types of organizations possess these

9 Price Risk Management skill sets?

10 A The speculative activities pursued by Idaho

11 Power affiliates revolve around exactly these skill sets.

12 Speculative transactions that are not based on analysis of

13 forward market prices, the underlying fundamental

14 production costs of the marketplace and a perception of

15 market supply/demand balances, are essentially decisions

16 to place bets without justification for returns. I

17 believe IdaCorp to be a fundamentally well managed

18 organization that would not place its corporate well

19 being at risk for unresearched "gambles." Therefore, I

20 believe that IdaCorp possesses these skill sets

21 internally.

22 These skill sets are contained in affiliates of

23 Idaho Power Company. The specific affiliates that I have

24 identified are:

25 * IDACORP Energy Solutions, LP (IES)

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1 * IdaWest

2 The second component of the skills necessary to

3 provide price risk management services for regulated

4 customers is the ability to calculate exposures to

5 forward market price movements arising from a customer

6 consumption pattern. It is my understanding that the

7 existing computer hardware and software systems and

8 supporting staff skills were transferred from IPC to IES

9 under the IPC-IES services agreement. It is also my

10 understanding that IdaCorp and IES portrayed to Staff and

11 customers at workshops discussing the IPC-IES services

12 agreement that these resources would still be utilized

13 for regulated customer purposes after the transfer. The

14 responses to staff data requests (see Exhibit 107)

15 indicate that IES has implemented a number of "best

16 practice" risk management practices. Therefore, I

17 believe that IdaCorp's subsidiaries, though possibly not

18 within IPC, have created and possesses the skills

19 necessary for this component of price risk management

20 services.

21 The third component of price risk management

22 is the creation of fundamentally sound internal policies,

23 procedures and processes for the price risk management

24 decision, market transaction execution and processing

25 functions. I have been unable, at this time, to

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1 determine the complete nature of the IdaCorp policies and

2 procedures and processes. However, I believe that the

3 IPC policies, procedures, and processes that have been

4 provided for my review prior to this testimony, are not

5 sufficient to assure that IPC decisions to accept or

6 reject long-term transactions for price risk management

7 purposes - or for any other purpose - are made in a

8 consistent and controlled manner. The lack of policies,

9 procedures, and processes undermines any assertion by IPC

10 that price risk management is or is not advisable for the

11 regulated customers. An absence of these structures will

12 inherently make price risk management less consistent and

13 systematized, which frequently results in an internal

14 perception that hedging activities are riskier than they

15 may possibly be.

16 Q What are the implications of the absence of

17 certain "best practice" risk management systems for IPC?

18 A This lack of structure also calls into question

19 any prior decisions made by IPC because there is no clear

20 basis for their decision-making. The determination of

21 whether a transaction is advisable depends on three

22 factors: 1) the current prices and implied volatility of

23 prices in the forward market; 2) the net exposure of the

24 risk position to price movements; and 3) the risk

25 tolerance of the entity for which the price risk decision

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1 is being made. I acknowledge that there is a wide degree

2 of latitude in what may comprise an acceptable decision

3 based on these factors. I recommend that the Commission

4 grant IdaCorp and IPC a significant amount of future

5 discretion concerning the creation of mechanisms for

6 supporting the price risk management decision.

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8 (Page 9, line 7 through page 11, line 16 has

9 been removed from the testimony by agreement of the

10 parties.)

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17 Q What is your understanding of the

18 relationship between IES and Idaho Power?

19 A My understanding, prior to the filing of

20 testimony by Idaho Power, was that the Company had

21 transferred its trading and risk management operations to

22 IES under an Electric Supply Management Services

23 Agreement ("Agreement"). In return for that transfer

24 Idaho Power has an obligation to pay IES approximately

25 $4.8 million per year, which is closely equivalent to

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1 100% of the cost of those operations in the most recent

2 rate proceeding for Idaho Power. This transfer between

3 IPC and IES allows IES to participate in the speculative

4 market, and allows the IdaCorp family of companies to

5 retain transactional and risk management skills. Keeping

6 these skill sets within IdaCorp is a benefit to both the

7 Company and the regulated customers.

8 It is my understanding that the retention of

9 skill sets was a critical component of the rationale for

10 approving the Agreement. I believe that the transfer of

11 transactional and risk management skill sets to IES

12 without retaining access to those skill sets

13 significantly diminishes Idaho Power's ability to

14 function effectively in deregulated wholesale energy

15 markets. Since Idaho Power will be compelled to

16 participate in those markets due to the fluctuations in

17 generating capabilities of hydroelectric generation

18 resources, effective participation in the wholesale

19 energy market will be critical to Idaho Power's regulated

20 customers.

21 Q What is your understanding of the current

22 services provided for Idaho Power by IES?

23 A In keeping with the understanding expressed

24 above, IES is participating in the near, medium, and

25 long-term markets at the Idaho Power interconnections to

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1 the regional markets. Furthermore, IES is gaining

2 insights into the market behavior, expected direction of

3 price movement, and the implied market volatility

4 expected by the trading community. Speculative trading

5 necessitates a significant investment in risk management

6 infrastructure and skills. I believe it was assumed that

7 IES would make these investments to protect its

8 speculative positions, while educating Idaho Power in the

9 process. Because of the $4.8 million dollar cost paid by

10 Idaho Power to IES, it seems rational Idaho Power should

11 receive constant advice and education from IES. My

12 understanding is that Idaho Power would be able to

13 utilize the IES risk management staff to act on behalf of

14 the regulated customers in fashion similar to what they

15 did while Idaho Power had the information and systems

16 necessary to make prudent decisions on behalf of the

17 regulated customers.

18 However, from the testimony of witness Gale

19 in the Commission Case No. IPC-E-01-16 (pg 4 line 12) and

20 Case Nos. IPC-E-7/11 Hoyd (pg 14 line 4), it appears that

21 IES may adopt a more restricted view of these

22 responsibilities under the Agreement. The testimony

23 indicates that the support provided by IES may be

24 restricted to the real time and day-ahead management of the

25 Idaho Power physical deliveries of energy, the

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1 "assurance that system resources are managed to the

2 benefit of the customers," and the provision of certain

3 limited audit information.

4 Idaho Power should clearly indicate whether

5 it intends to rely on IES for longer-term price risk

6 management. If my interpretation of the Gale and

7 Andersen testimony is correct, the remaining resources do

8 not appear sufficient for the exercise of prudent actions

9 by Idaho Power within the wholesale power market on

10 behalf of the regulated customers without the skill sets

11 provided by IES.

12 Q Do you believe that the current interactions

13 between Idaho Power and IES provide instances where the

14 risks and rewards are shifted between IPC and IES are

15 without appropriate customer compensation?

16 A. Yes. IES has received certain benefits from

17 the relationship that have, or could have allowed, IES to

18 transact with lower risk and to shift certain

19 transactional costs to Idaho Power and its customers.

20 The specific areas of concern are:

21 * Prior knowledge of market liquidity

22 * Credit risks

23 * Pricing formulae

24 * Regulatory authorities necessary for IES to

25 participate in the wholesale energy market

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1 * Access to generation optionality

2 Each of these areas will be discussed

3 separately in the following testimony.

4 My fundamental premise is that Idaho Power

5 cannot reduce the risks of IES trading activities without

6 transferring a benefit to IES that is unavailable to

7 other market participants, while at the same time

8 reducing the ability of Idaho Power Company customers to

9 achieve the most competitive market pricing for needed

10 resources. Without transaction specific data, any

11 estimation of whether IES executed transactions to

12 implement some of the benefits, and the degree to

13 which IES was successful in profiting from these benefits,

14 would be highly subjective. However, the fact that such

15 activities could take place without adequate customer

16 compensation, is only an element of the consumer cost.

17 As discussed later, an increased open market transaction

18 costs can arise from market perception of inter-affiliate

19 advantage. Other benefits relating to the reduction of

20 internal transaction or operating costs, such as

21 reduction in credit risks, could be determined from the

22 cost of securing such benefits from the open market.

23 (Page 15, line 23 through page 17, line 17

24 has been removed from the testimony by agreement of the

25 parties.)

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18 Q What is your understanding of the current

19 pricing for transactions between Idaho Power and IES?

20 A My understanding is that the pricing of

21 transactions beyond the next delivery day is done at the

22 purchase price. It appears, from Company testimony (IPC-

23 E-01-16, Gale, pg 4-line 15, "all wholesale transaction

24 between Idaho Power and IES will be at market prices" and

25 Gale pg 18 line 2) that no transactions are done directly

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1 between Idaho Power and IES for periods beyond next day

2 delivery. IES offers to act as a broker for all such

3 transactions. I have been unable to determine whether

4 IES charges a brokerage fee for arranging such

5 transactions or if such a fee is charged, it is in

6 keeping with normal brokerage fees charged in the

7 industry.

8 For day ahead and real time pricing, IES uses

9 a "representative" market price based on either Mid-C (the

10 Mid-Columbia wholesale market trading hub in Washington

11 state) or Palo Verde (the California-Nevada border

12 wholesale market trading hub) market prices. The pricing

13 is based on the market prices for those points, not the

14 actual transaction costs of IES for securing or selling

15 the power.

16 Any difference between the purchase price and

17 the representative market price, or transmission

18 arbitrage obtained or lost by IES, is retained on the

19 speculative book. Pricing differential and transmission

20 arbitrage opportunities are addressed in subsequent

21 portions of my testimony.

22 Q What are the trading risks or opportunities

23 that could be experienced by IES in the management of

24 Idaho Power service obligations under the Agreement?

25 A The manner in which IES interprets the

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1 relationship between Idaho Power and IES significantly

2 constrains the risks under the Agreement while retaining

3 a significant number of the advantages.

4 In regards to the short term (real-time and

5 day-ahead), Idaho Power represents the largest market

6 participant for firm energy transactions for power at the

7 interconnections of Idaho Power with other regional

8 market participants. IES, by managing the transaction

9 flow, can assure that Idaho Power and IES are not

10 simultaneously attempting to complete transactions in

11 periods of limited liquidity. In addition, if IES

12 perceives that liquidity at certain pricing locations is

13 constrained, then IES may anticipate that IPC purchases

14 will have the impact of moving wholesale market prices in

15 a specific direction.

16 While this may not impact the pricing at the

17 representative pricing points, it may have a noticeable

18 impact on the Idaho border prices. If IES believes its

19 actions on behalf of Idaho Power could shift the local

20 prices noticeably from the representative prices, IES has

21 the opportunity to create lower risk returns.

22 For example, if IES determines that IPC will

23 require an additional 500 MW per hour of on-peak power

24 three days in the future in a market where the maximum

25 size of on-peak energy trading over the last week was 150

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1 MW per hour, then IES may anticipate that prices could

2 move higher. By purchasing block power for future

3 periods in anticipation of this demand, IES may be able

4 to position itself to capture returns due to increased

5 market knowledge. This practice has occurred frequently

6 enough in commodity markets to develop a name "front

7 running" and to necessitate Commodity Futures Trading

8 Commission regulations to prohibit this behavior by

9 commodity brokers.

10 With regard to the long-term markets, IES

11 again has knowledge prior to all other market participants

12 of upcoming Idaho Power market activity. Information given

13 to me indicates that IES is provided and has participated

14 in load forecasting and other activities that define the

15 energy purchasing and sales exposure of Idaho Power. In

16 addition, the audit requests submitted and responded to

17 in this proceeding indicate that IES operates whatever

18 risk position tracking software is utilized by Idaho

19 Power to manage its wholesale market position. I am

20 concerned about the existence, or lack thereof, of

21 software security or firewalls to segregate Idaho Power

22 information from IES.

23 Without these firewalls, IES has access to

24 Idaho Power's intended market activities and consequently

25 has an advantage that no other participants in the Idaho

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1 wholesale power market possess - the understanding of

2 when IES's speculative position would be in conflict with

3 future actions that Idaho Power would be expected to

4 assume in the market. For example, a speculator in

5 wholesale power would understand that Idaho Power may at

6 times buy and other times sell. This participant must be

7 concerned that any speculative position would be impacted

8 by Idaho Power activities. If a speculator purchased

9 power for June, only to have Idaho Power soon thereafter

10 determine it had excess power for the upcoming June and

11 therefore need to sell power for that period, the likely

12 result would be that the speculative position would lose

13 money without other market actions.

14 Therefore, knowledge of risk exposure and

15 transaction decisions of Idaho Power prior to other

16 market participants reduces IES's speculative risks in

17 the Idaho region. However, Idaho Power customers receive

18 no benefits from the risk reduction experienced by IES.

19 Q Do you believe that hedging activity by IPC

20 could reduce the benefit to IES of access to IPC risk

21 positions?

22 A Yes. Actions by IPC to reduce its wholesale

23 market price risk are, by their nature, intended to

24 reduce IPC's need to transact in the sport market. This

25 reduction should, in aggregate, reduce IPC's competition

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1 for short-term market liquidity. Energy commodity

2 markets generally experience their highest volatility,

3 and therefore most rapid price changes, in the delivery

4 month. Prior hedging of risk, by reducing IPC's delivery

5 month activities, could reduce IES's knowledge advantage

6 in the marketplace.

7 Q If Idaho Power Company's purchasing practices

8 changed from entering into transactions for time periods

9 beyond thirty days to a practice of entering into

10 transactions for periods of less than thirty days, do you

11 believe it would create opportunities for IES to benefit

12 from lower risk transactions?

13 A Yes, I do believe this could create speculative

14 opportunities for IES at lower risk than that of other

15 speculative market participants. As discussed above,

16 knowledge of the activities of organizations with

17 significant market positions allows lower risk trading.

18 Any potential change to increase IPC's exposure to

19 delivery month prices increases IES's knowledge advantage

20 during the period of time when that advantage has the

21 potential to create greatest leverage.

22 Q How would this occur?

23 A In this case IES would receive, through its

24 assistance in load forecasting to Idaho Power, knowledge

25 of Idaho Power's need to purchase or sell energy in the

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1 wholesale market for forward periods for high, normal, and

2 low water flow scenarios as well as high, normal, and

3 low demand scenarios. With this information, IES has a

4 forecast of the likelihood that Idaho Power will have

5 purchasing or sales transactions during a delivery month.

6 IES can assess the likely market liquidity during that

7 period, estimate the Idaho Power impact on market

8 liquidity during that period, and make appropriate

9 speculative transactions to take advantage of the likely

10 market price direction during that period.

11 This is not to imply that IES, by the nature

12 of this information, is guaranteed profitable trading

13 activities. Abnormal and abrupt conditions can occur,

14 plant outages may take place, and market pressures from

15 interconnected markets - such as California - may

16 overwhelm the market balance of the Idaho region. I am

17 not implying that IES is gaining perfect market

18 knowledge. However, IES is gaining better market

19 knowledge than other participants in the region. This

20 knowledge reduces the risks of speculative activities.

21 It does not appear that the Idaho Power regulated

22 customers have been compensated for that risk reduction

23 in any manner.

24 Without access to all transactions by IES and

25 IPC, information as to whether IES was securing

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1 speculative positions to have risk exposures in

2 opposition to IPC, cannot be determined. Without

3 specific transaction level information for both the

4 operational and non-operational books as to what the

5 price movements were from the IES transaction date until

6 the delivery date, I can not estimate the magnitude of

7 IES potential gains from this knowledge. However, it is

8 simple to note that a $10/MWhr movement for a 100 MW

9 exposure for any given week is $80,000 ($10/MWH *100MW*

10 80 on-peak hours). The price movements experienced

11 during the later portion of the PCA year under review in

12 this proceeding were, at times, orders of magnitude

13 greater. I believe that this is ample evidence that

14 opportunities did exist for IES to make substantial

15 profits from the prior knowledge of Idaho Power

16 purchasing requirements.

17 Q What additional benefits do you believe

18 IdaCorp and its affiliates received from Idaho Power during

19 last years PCA?

20 A IES received its FERC power marketing license

21 on April 27, 2001. Prior to that time, IES was not

22 legally authorized to trade wholesale power. IPC

23 responses to staff data request (see Exhibit 107)

24 indicate that all transactions on IES's behalf were

25 actually entered into by Idaho Power. This implies that

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1 all counterparty credit risk for IES speculative

2 transactions was actually assumed by Idaho Power. The

3 open market cost of such credit enhancement is normally

4 between 1-2% of the notional amount, i.e., the total

5 value of the transaction as determined by multiplying all

6 volumes for the life of the agreement by the current

7 pricing under the agreement. This is a cost of doing

8 business that IES avoided by receiving free credit

9 enhancement by the regulated customers.

10 In addition, IES was allowed to enter the

11 market months earlier than it could have otherwise,

12 giving IES access to the market volatility of the west

13 during 2000/2001. Prior to receiving its power marketer

14 certificate authority from the Federal Energy Regulatory

15 Commission, it was unlawful for IES to enter into

16 wholesale energy market transactions as a principal.

17 Without Idaho Power standing behind all IES transactions,

18 IES would not have received any profits prior to April

19 2001. In addition, IES was also allowed to build name

20 recognition in the market place months earlier and will

21 likely be considered part of Idaho Power for several

22 months into the future, extending its credit advantage.

23 Q Do you believe there are opportunities for

24 IES to obtain minimal or risk-free profits under the

25 IPC-IES pricing methodology?

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1 A Yes, opportunities could exist under the

2 Agreement. In the area of real-time and day-ahead power

3 purchases for Idaho Power by IES, a strong possibility

4 exists for transmission arbitrage under the contract

5 pricing. Arbitrage is an instance where a discrepancy

6 between two different pricing points exists such that a

7 transaction can be entered into to capture the difference

8 as a profit without risk.

9 My understanding is that transmission services

10 are transferred to IES at cost. In addition, power

11 purchased at the Idaho border for Idaho Power by IES is

12 transferred based on the representative market locations

13 - not the border price. Since the transportation price

14 is known, it is possible for IES to determine whether

15 Idaho border prices are less than the representative

16 market price plus transmission. If there is a

17 differential, IES collects that differential as a profit.

18 This profit is risk-free and is not shared with the

19 customers.

20 For example, if for the next day deliveries

21 of energy the Mid-C wholesale energy market is transacting

22 at a value of $100/MWhr and the price of wholesale energy

23 at the Idaho border with Washington State is $98/MWhr, an

24 arbitrage opportunity would exist under the pricing

25 formula. As currently utilized, the formula would price

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1 energy at the border at a price equal to the Mid-C price

2 plus approximately $1.25/MWHr of transmission costs - or

3 $101.25/MWhr. Purchasing energy delivered at the border

4 could occur at a cost of $98/MWhr without requiring any

5 purchase at Mid-C. The difference between the price

6 under the formula - $101.25/MWhr - and the market price -

7 $98/MWhr - would be retained by IES and would have

8 required no risk by IES on the transaction.

9 Another area of potential rewards to IES that

10 is not solely dependant upon the contract pricing

11 mechanism is the creation of speculative positions in

12 anticipation of Idaho Power open market transactions. If

13 IES, through its participation in load forecasting and

14 management of Idaho Power's risk position information,

15 has knowledge that Idaho Power will have the need for

16 significant day-ahead and real-time purchases, IES can

17 enter into speculative transactions that reflect Idaho

18 Power's future needs. For example, if IES has knowledge

19 that Idaho Power will require significant energy

20 purchases for on-peak periods during the next week, IES

21 can take speculative positions to purchase power during

22 that delivery period prior to the execution of the power

23 purchase for Idaho Power. While it is possible that

24 weather or other conditions will remove that need, IES

25 actions will be made with knowledge:

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1 * of the projected buying or sales needs of

2 the largest firm energy market participant

3 at the interconnections of Idaho Power with

4 other regional market participants,

5 * that IES will know before any other market

6 participant if those needs shift,

7 * that IES will view all market transaction

8 structures of Idaho Power, and

9 * that if IES sells power to Idaho Power at

10 values above the IES purchase price, IES

11 will receive a benefit.

12 Q Can there be additional costs to Idaho Power

13 customers from the IES relationship?

14 A. Yes. If the other market participants that

15 might transact with Idaho Power perceive that Idaho

16 Power, either explicitly or implicitly, favors IES in its

17 transactions, then there is a significant risk that these

18 market participants may decide to withdraw from the

19 business of providing energy to Idaho Power. Another

20 central premise of deregulated markets is that an open

21 and freely contested market is necessary for efficient

22 market pricing. If the Idaho Power-IES relationship

23 reduces the willingness of third parties to participate

24 actively in the wholesale market for energy at the border

25 of the IPC system, inefficient pricing may occur. This

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1 inefficiency may occur during any time period - real-time

2 to multi-year forward periods - that the market lacks an

3 adequate number of participants. These inefficiencies

4 reduce market liquidity and increase prices. Since Idaho

5 Power's regulated customers are paying market prices, they

6 will pay more as a result of decreased liquidity.

7 Several of my recommendations have dealt with

8 the access to internal Idaho Power data by IES prior to

9 other market participants. While the major reason for my

10 recommendations have been to reduce IES's ability to

11 decrease its own risk on speculative transactions in

12 relation to other market participants, the potential

13 reduction in market liquidity and the negative impact on

14 Idaho Power customers if the market loses participants

15 should not be ignored.

16 Q Are there additional possible benefits that

17 IES may receive from its relationship that current audit

18 information may be unable to identify?

19 A I believe there are additional risk reducing

20 or risk transferring transactions that would be impossible

21 to identify without access to all trading information for

22 IdaCorp and its affiliates. I am not stating such

23 transactions have or have not occurred, only that

24 information necessary to make a determination is not

25 available at this time.

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1 The transaction types referred to above

2 relate to the nature of generation assets as a real option

3 transaction. Generation facilities, in financial

4 engineering terms, constitute a series of options that

5 can be exercised on an hourly, daily, weekly, or monthly

6 basis. Since the generation owner has the right but not

7 the obligation to utilize the generation asset, in

8 financial engineering terms this would be considered owning

9 the option of being "long".

10 The owner of an option has the ability, using

11 financial formulae such as the Black-Scholes option

12 model, to determine the efficient hedge ratio for sales

13 of production against the option to produce output.

14 Financial theory can illustrate that the constant

15 readjustment of this efficient hedging ratio has the

16 effect of allowing risk-free monitization of the

17 production optionality. The only residual risk is that

18 market price movement, or volatility, will not occur and

19 the cost of acquiring the option, the fixed carrying

20 costs of the asset, will not be recovered.

21 However, in the case of Idaho Power and IES,

22 the fixed carrying costs of the generation assets are

23 recovered through regulated rates. If, and I stress that

24 to my knowledge the information necessary to perform the

25 analysis has not been made available to either myself or

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1 IPUC Staff, IES were to transact knowing that Idaho Power

2 generation assets would have excess power to sell in the

3 future, it could be possible for IES to utilize those

4 assets to form the basis for this type of transaction.

5 This type of trading would serve to reduce the risk of

6 IES while providing potentially profitable trading

7 activities.

8 (Page 31, line 8 through page 33, line 13 has

9 been removed from the testimony by agreement of the

10 parties.)

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14 Q Staff has recommended that IES be compensated

15 at the lower of IES's actual cost of purchasing power for

16 consumption or the market price of energy at the

17 "representative price" under the IPC-IES agreement at

18 time of consumption for purchases for Idaho Power

19 regulated customers. Staff has also recommended that

20 Idaho Power be compensated at the higher of IES's actual

21 cost of revenues for sale or the market price of energy

22 at the time of delivery of sales of power by Idaho Power.

23 Do you agree with these recommendations?

24 A Yes, the IPUC Staff has identified one of the

25 potential flaws in transfer pricing mechanisms - the

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1 ability to create risk arbitrage between two locations.

2 Under the current pricing system, IES has the opportunity

3 to determine whether power purchased at the IPC

4 interconnections with other transmission systems is

5 priced at a different value than that represented under

6 the IPC-IES contract price of Mid-C market price plus the

7 tariff costs of transmission to the IPC system from that

8 point.

9 If the cost of wholesale power at the IPC

10 border is less than the IPC-IES reference price for real-

11 time or day-ahead power, the difference is retained by

12 IES. However, IES has taken no risk to obtain that

13 value. Rather, that value is implicit in the IPC

14 customer load and physical assets. Prior to

15 implementation of the pricing structure of this

16 Agreement, risk-free trades were passed on to the

17 ratepayers for their benefit. As such, I agree with

18 Staff that the existing pricing structure under the IPC-

19 IES contract should be modified to assure that the risk-

20 free arbitrage is captured as a customer benefit.

21 (Page 34, line 21 through the end of the

22 testimony has been removed from the testimony by agreement

23 of the parties.)

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1 (The following proceedings were had in

2 open hearing.)

3 COMMISSIONER KJELLANDER: All right; so with

4 that, then, you would tender your witness for

5 cross-examination?

6 MS. NORDSTROM: I do.

7 COMMISSIONER KJELLANDER: Okay, and we'll

8 begin cross with Mr. Richardson.

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

10 COMMISSIONER KJELLANDER: And with that, now

11 we're approaching about ten minutes before noon and it

12 would be my preference to break until about 1:15, so when

13 we return, then, we will be at a point where Mr. Ripley can

14 begin his cross and with that, we will be off the record.

15 (Noon recess.)

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CSB REPORTING LORD
Wilder, Idaho 83676 Staff