20090108Vol IV [technical hearing] pgs 322-655.pdf

ORIGINAL
.;~BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF I DAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS
RATES AND CHARGES FOR ELECTRIC
SERVICE TO ELECTRIC CUSTOMERS IN
THE STATE OF IDAHO.
)
)CASE
)
)
)
)
)
Idaho Pubfic Utilties Commission
. Office of the SecretaryRECEIVED
JAN - 8 20
Bo kI
NO. IPC-E-08-10
BEFORE
COMMISSIONER MARSHA H. SMITH (Presiding)
COMMISSIONER MACK A. REDFORD
COMMISSIONER JIM D. KEMPTON.
PLACE:Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE:December 16, 2008
VOLUME IV - Pages 322 - 655
."
CSB REPORTING
Constance S. Bucy, CSR No. 187
23876 Applewood Way * Wilder, Idaho 83676
[phone] * [phone]
Email csb(Weritagewifi.com
.
.
.
10
11
12
13
14
15
20
21
22
23
24
25
1 APPEARANCES
2 For the Staff:
3
4
5 For Idaho Power Company:
Neil Price, Esq.
Deputy Attorney General
472 West Washington
Boise, Idaho 83720-0074
Barton L. Kline, Esq.
and Lisa D. Nordstrom, Esq.
and Donovan E. Walker, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707-0070
RICHARDSON & 0' LEARY
by Peter J. Richardson, Esq.
Post Office Box 7218
Boise, Idaho 83702
RACINE, OLSEN, NYE, BUDGE
& BAILEY
by Eric L. Olsen, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
Arthur Perry Bruder, Esq.
Assistant General Counsel
U. S. Department of Energy
1000 Independence Ave., SW
Washington, DC 20585
GIVENS PURSLEY LLP
by Conley E. Ward, Esq.
Post Office Box 2720
Boise, Idaho 83701-2720
BOEHM, KURTZ & LOWRY
by Kurt J. Boehm, Esq.
36 E. Seventh Street
Suite 1510
Cincinnati, Ohio 45202
-and-
FISHER PUSCH & ALDERMAN LLPby John R. Hamond, Jr., Esq.
Post Office Box 1308
Boise, Idaho 83701
6
7
8
9
For Industrial Customers
of Idaho Power:
For Idaho Irrigation
Pumpers Association:
For The United States
Department of Energy:
16
17 For Micron Technology,
Inc. :
18
19
For The Kroger Company:
(Of Record)
(Of Record)
CSB REPORTING
[phone]
APPEARANCES
1 A P P E ARANCES (Continued).2
3 For the Community Action Brad M.Purdy, Esq.
Partnership of Idaho:Attorney at Law
4 2019 North 17th Street
Boise,Idaho 83702
5
For Snake River Alliance:Mr.Ken Miller
6 5400 West Franklin
Boise,Idaho 83705
7
8
9
10
11
12.13
14
15
16
17
18
19
20
21
22
23
24.25
CSB REPORTING APPEARANCES
(208 )890-5198
.1 EXHIBITS
2
3 NUMBER DESCRIPTION PAGE
4 FOR I DAHO POWER COMPANY:
5 35 - Idaho Power, CWIP Related to Hells
Canyon Relicensing
Premarked
6 36 - Idaho Power, Dataset for Premarked
7 Jurisdictional Revenue Requirement,
Summary of Results
8 37 - Idaho Power, Dataset for Premarked
9 Jurisdictional Revenue Requirement,
Table 1
10 38 - Idaho Power, Dataset for Premarked
11 Jurisdictional Revenue Requirement,
Table 2
12.13
39 - Idaho Power, Dataset for Premarked
Jurisdictional Revenue Requirement,
Table 3
14 40 - Idaho Power, Dataset for Premarked
15 Jurisdictional Revenue Requirement,
Table 4
16 41 - Idaho Power, Dataset for Premarked
17 Jurisdictional Revenue Requirement,
Table 5
18 42 - Idaho Power, Dataset for Premarked
19 Jurisdictional Revenue Requirement,
Table 6
20 43 - Idaho Power, Dataset for Premarked
21 Jurisdictional Revenue Requirement,
Table 7
22 44 - Idaho Power, Dataset for Premarked
23 Jurisdictional Revenue Requirement,
Table 8
24
. 25
CSB REPORTING
Wilder, Idaho 83676
EXHIBITS
.
.
.
1 E X H I BIT S (Continued)
2
3 NUMBER DESCRIPTION
5 45 - Idaho Power, Dataset for Premarked
Jurisdictional Revenue Requirement,6 Table 9
7 46 - Idaho Power, Jurisdictional Premarked
Revenue Requirement
4 FOR IDAHO POWER COMPANY:
8
9
47 - IPCO Power Supply Costs for
Normalized Loads over 80 Water
Year Conditions
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
PAGE
10
11
48 - Idaho Power, Cogeneration & Small
Power Production Rate Department
Normalized Information
12
49 - PCA Regression Derivation
13
14
50 - Marginal Energy Costs, Summary
Total
15 51 - PCA Computational Factors
16 52 - Annualizing Plant Adj ustment
17 53 - Functionalization & Classification
of Costs
18
54 - Summary of Functionalized Costs
19
55 - Allocation to Classes
20
56 - Summary of Class Allocations
21
57 - Revenue Requirement Summary
22
58 - Class Cost-of-Service Unit Costs
23
24
59 - Development of Weighted Demand &
Energy Allocators
25
CSB REPORTING"
Wilder, Idaho 83676
EXHIBITS
.
.
.
20
21
22
23
24
25
1 E X H I BIT S (Continued)
2
3 NUMBER DESCRIPTION PAGE
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
4 FOR IDAHO POWER COMPANY:
5
6
60 - Development of Weighted Demand &
Energy Allocators
7 61 - Revenue Requirement Summary
8 62 - Functionalization & Classification
of Costs
9
63 - Summary of Functionalized Costs
10
64 - Allocation to Classes
11
65 - Summary of Class Allocations
12
66 - Revenue Requirement Summary
13
67 - Class Cost-of-Service Unit Costs
14
15
68 - Development of Demand & EnergyAllocators
16 69 - Comparative Cost-Of-Service
Study Results
17
18
70 - Proformed Normalized Sales and
Revenue
19 71 - Class Cost of Service
Functionalized Costs
87 - IPCo Power Supply Costs for 2008
Normalized Loads Over 80 Water
Year Conditions
CSB REPORTING
Wilder, Idaho' 83676
EXHIBITS
.
.
.
18
19
20
21
22
23
24
25
1
2
E X H I BIT S (Continued)
3 NUMBER DESCRIPTION PAGE
4 FOR THE IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.:
5
6
308 - Exhibit Nos. 40, 41 & 43 of
Maggie Brilz in Case No.
IPC-E-03-13
Identified 590
7
8 FOR MICRON TECHNOLOGY, INC.:
9 708 - Marginal Energy Costs, Summary
Total Identified 571
10
11
709 - Marginal Energy Costs, Summary
Total Identified 572
12
13
14
15
16
17
CSB REPORTING
Wilder, Idaho 83676 EXHIBITS
.
.
20
1 BOISE, IDAHO, TUESDAY, DECEMBER 16, 2008, 1:30 P. M.
2
3
4 COMMISSIONER SMITH:Good afternoon,
5 ladies and gentlemen. We're ready to go back on the
6 record and I see we have had Mr. Kline transformed into
7 Ms. Nordstrom.
8 MS. NORDSTROM: That's correct. Before we
9 get started, would it be possible to excuse Maggie Brilz
10 from the further proceedings?
11 COMMISSIONER SMITH: Is there any
12 objection to excusing Maggie Brilz? Seeing none, she's
13 excused.
14 MS. NORDSTROM: Thank you. During the
15 questioning of Theresa Drake, Commissioner Kempton asked
16 about a Commission Order that referred to specific tests
17 and public policy considerations for cost-effective
18 demand side management and I have a copy of that Order if
19 you would like.
COMMISSIONER SMITH: And what's the Order
21 number?
22 MS. NORDSTROM: It is Order No. 28894,
23 specifically referenced on page 7.
24.25
COMMISSIONER SMITH: Okay, thank you.
MS. NORDSTROM: You're welcome. Idaho
CSB REPORTING
[phone]
322 COLLOQUY
.
.
1 Power calls Catherine Miller as its next witness.
2
3 CATHERINE M. MILLER,
4 produced as a witness at the instance of the Idaho Power
5 Company, having been first duly sworn, was examined and
6 testified as follows:
7
8 DIRECT EXAMINATION
9
10 BY MS. NORDSTROM:
11 Q Ms. Miller, please state your name and
12 spell your last name for the record.
13 A My name is Catherine M. Miller. People
14 commonly refer to me as Catie Miller, M-i-l-l-e-r.
15 Q By whom are you employed and in what
16 capacity?
17 A I'm employed by Idaho Power Company as
18 director of strategic analysis.
19 Q Are you the same Catherine Miller that
20 filed direct testimony on June 27th, 2008?
21
22
23
24.25
A Yes, I am.
Q Did you prepare Exhibit 35?
A Yes.
Q Did you also file rebuttal testimony on
December 3rd, 2008?
CSB REPORTING
[phone]
323 MILLER (Di)
Idaho Power Company
.
.
.
1 A Yes.
2 Q Did you have any exhibits with your
3 rebuttal testimony?
4 A No, I do not believe I did.
5 Q Do you have any corrections, changes or
6 updates to your testimony or exhibit?
7 A Yes, I do.
8 (Mr. Gale distributing documents.)
9 MS. NORDSTROM: Idaho Power is currently
10 distributing a list of your corrections for the
11 convenience of the Commission and the parties,
12 particularly since numbers are involved.
13 Q BY MS. NORDSTROM:Could you please
14 describe your changes?
15 A Yes. In my direct testimony, page 9, line
16 10, replace "30" with "29". On page 12, line 20, replace
17 "42" with "39", and I'm going to back up because I think
18 I misquoted on the first line. Replace "30" with "29".
19 Page 12, line 20, replace "42" with "39". Page 13, line
20 14, replace "three" with "two". Page 14, line 19,
21 replace "40" with "39" and in my rebuttal testimony, on
22 page 2, lines 10 through 15, delete the following
23 sentence, "And, finally, I will respond to Staff Witness
24 Vaughn's proposal that the Company request Commission
25 authori ty to place the Hell's Canyon relicensing proj ect
CSB REPORTING
[phone]
324 MILLER (Di)
Idaho Power Company
.
.
1 in base rates before a permanent license is granted by
2 the Federal Energy Regulatory Commission, (FERC)."
3 Q BY MS. NORDSTROM: Ms. Miller --
4 COMMISSIONER SMITH: And could we add
5 rebuttal page 14, line 10, "principle" to "principal"?
6 MS. NORDSTROM: Yes.
7 THE WITNESS: Yes.
8 MS. NORDSTROM: Thank you.
9 Q BY MS. NORDSTROM: Ms. Miller, is the
10 reason you delete the sentence on page 2 of your rebuttal
11 testimony because Mr. Gale addresses this and other
12 CWIP-related policy issues in his rebuttal testimony?
13 A Yes.
14 Q If I were to ask you the questions set out
15 in your corrected prefiled direct and rebuttal testimony,
16 would your answers be the same today?
17 A Yes, they would.
18 MS. NORDSTROM: I would move that the
19 pre filed direct and rebuttal testimony of Catherine
20 Miller be spread upon the record as if read and Exhibit
21 35 be marked for identification.
22 COMMISSIONER SMITH: If there's no
23 objection, that is so ordered.
24 (The following prefiled direct and.25 rebuttal testimony of Ms. Catherine Miller is spread upon
the record.)
CSB REPORTING
[phone]
325 MILLER (Di)
Idaho Power Company
.
.
.
1 Q.Please state your name and business address.
2 A.My name is Catherine M. Miller. My business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what capacity?
5 A.I am employed by Idaho Power Company as
6 Director of Strategic Analysis.
7 Q.Please describe your educational background.
8 A.I graduated with high honors in 1991 from Idaho
9 State Uni versi ty, Pocatello, Idaho , receiving a Bachelor
10 of Business Administration degree in Accounting. In
11 1998, I received a Master of Business Administration
12 degree from Boise State Uni versi ty in Boise, Idaho. I
13 have attended numerous seminars and conferences on
14 accounting, management, and finance issues related to the
15 utili ty industry. I have been a Certified Public
16 Accountant licensed in the State of Idaho since 1992.
17 Q.Please describe your business experience with
18 Idaho Power.
19 A.In 1991, I began my association with Idaho
20 Power Company as external auditor for Deloi tte & Touche
21 LLP, the Company's external audit firm. I joined Idaho
22 Power Company in May of 1994 as a Tax Analyst in the Tax
23 Department where I was responsible for preparing monthly
24
25
326 MILLER, DI 1
Idaho Power Company
.
.
.
1 tax accruals, tax forecasts, tax returns, and tax
2 analyses. In August of 1996, I was promoted to a
3 Business Analyst in the Financial Research and Support
4 Department. My duties as a Business Analyst included the
5 preparation of the Company's financial forecasts and the
6 preparation of a wide range of financial and regulatory
7 analyses. In February of 2001, I was promoted to Finance
8 Team Leader III for the Strategic Analysis Department.
9 In that capacity, I became responsible for overall
10 financial support, forecast activities, and non-regulated
11 subsidiary accounting. Non-regulated subsidiary
12 accounting was eventually transferred out of the
13 Strategic Analysis Department.
14 In 2004, I was promoted to my current position
15 of Director of Strategic Analysis in the Corporate
16 Planning and Risk Management Department. I currently
17 supervise two departments, Strategic Analysis and
18 Regulatory Accounting and Support. Strategic Analysis
19 prepares the Company's consolidated financial forecasts,
20 provides updates to management, and prepares a wide range
21 of financial analyses as requested. Regulatory
22 Accounting and Support is responsible for all regulatory
23 accounting and coordinates Finance Department support of
24 regulatory filings.
25 Q. What is the purpose of your testimony in thisproceeding?
327 MILLER, DI 2
Idaho Power Company
.1 A. The purpose of my testimony is to request that
2 the Allowance for Funds Used During Construction
3 ("AFUDC") component of Construction Work in Progress
4 ("CWIP") for the Hells Canyon relicensing proj ect be
5 included in base rates. My testimony will support the
6 Company's request to include $7.6 million in rates to
7 recover a portion of the AFUDC included in CWIP resulting
8 from relicensing expenditures for Hells Canyon. The
9 Company is only requesting that it be permitted to
10 include in rates the amount needed to offset the
11 anticipated growth in AFUDC for the Hells Canyon
12 relicensing proj ect. To provide context for this.13
14
proposal, I will provide an overview of CWIP and AFUDC
and discuss the recent State of Idaho legislation
15 permitting the inclusion of CWIP in rate base. I will
16 describe what costs have been capitalized as CWIP for
17 Hells Canyon relicensing and provide CWIP account
18 (Account 107) balances as of December 31, 2007. I will
19 present Idaho Power's proposal to collect AFUDC as it is
20 incurred, explain why the Company is seeking recovery,
21 and provide the Company's recommendation on future
22 accounting and rate treatment that would be instituted
23 when the Commission authorizes implementation of the
24 Company's proposal..25
328 MILLER, DI 3
Idaho Power Company
.
.
. 25
1 OVERVIEW OF CWIP AN AFC
2 Q.As a preliminary matter, please explain the
3 relationship between CWIP and AFUDC.
4 A.CWIP represents the accumulation of all costs
5 associated with the construction of an asset, including
6 the cost of financing the construction expenditures.
7 Utilities record these costs in Account 107. In Idaho,
8 since the mid-1980s, CWIP has not been included in rate
9 base on a current basis and, as a result, financing costs
10 are capitalized and included in the CWIP account (Account
11 107). These capitalization costs are known as AFUDC and
12 are considered a component of CWIP.
13 When the plant is completed and placed in
14 service, the total cost of the plant including AFUDC is
15 moved to a specific plant in service account. This is
16 commonly referred to as placing an asset in rate base.
17 Once in rate base, the Company begins recovering the
18 costs (including AFUDC) of the plant. In effect, during
19 construction, Idaho Power is allowed to earn a return on
20 CWIP by accruing AFUDC. However, the cash recovery does
21 not occur until the associated plant is placed in rate
22 base. Because new electric generation and transmission
23 plants often have very long construction periods and
24 require significant funding,
329 MILLER, DI 4
Idaho Power Company
.
.
1 the delay in recovering financing costs has become a very
2 significant issue for Idaho Power and its customers.
3 Q.How has the Idaho Commission treated CWIP and
4 AFUDC in the past?
5 A.It is my understanding that with the
6 concurrence of the Commission, the 1984 Idaho Legislature
7 codified Idaho Code § 61-502A prohibiting the Commission
8 from setting rates for any utility that grants a return
9 on CWIP or property held for future use and which is not
10 currently used and useful in providing utility service
11 except upon its finding of an "extreme emergency." When
12 CWIP was excluded from rate base, the Commission was
13 required to allow the accumulation of AFUDC computed in
14 accordance with generally accepted accounting principles
15 ("GAAP") .
16 Q.Is it now permissible under Idaho law for the
17 Commission to allow a utility to place CWIP in base rates
18 and, in effect, allow the utility to earn and collect a
19 return on it before the plant is fully constructed?
20 A.Yes. While I am not an attorney, I have been
21 advised by legal counsel that in 2006 the Idaho
22 Legislature amended Idaho Code § 61-502A to give the
23 Commission broader authority to approve and set just,
24 reasonable, and fair rates for utility facilities under
. 25
330 MILLER, DI 5
Idaho Power Company
.
.
1 construction. The Legislature intended the amendment to
2 give the Commission latitude to allow recover of CWIP in
3 rate base to facilitate construction of facilities to
4 meet growing customer demands. According to the
5 Statement of Purpose of House Bill 694, the Commission
6 "may grant a utility a return on construction work in
7 progress or property held for future use which is not
8 currently used in providing utility service" if it
9 explicitly finds that doing so will serve the public
10 interest. The House Bill's Statement of Purpose also
11 nòted that the legislative changes "will help ensure that
12 development of energy and other utility facilities meet
13 the growing needs of Idaho citizens at a reasonable
14 cost. " The most important difference with this new law
15 is that the Company is now allowed to collect financing
16 costs incurred during the construction period which
17 improves cash flows.
18 Q.As a financial analyst, why is cash flow
19 important to Idaho Power?
20 A.When Idaho Power is in a period of significant
21 construction, collecting financing costs improves cash
22 flow, which leads to the improved cash flow coverage
23 ratios that are necessary to maintain Idaho Power's
24 credi t strength and its ability to access external.25 markets for funding construction acti vi ties. The
331 MILLER, DI 6
Idaho Power Company
.
.
.
1 importance of cash flow and credit strength is discussed
2 in greater detail in Mr. Steven Keen's testimony. The
3 legislation allows for this cash flow improvement.
4 Q.Do hydroelectric relicensing expenses for
5 existing facilities like the Hells Canyon Complex qualify
6 as CWIP?
7 A.Yes. The Hells Canyon Complex is the backbone
8 of Idaho Power's hydro generation and with a nameplate
9 capacity of 1,167 MW, contributes nearly two-thirds of
10 the Company's low-cost, emission-free hydro generation
11 capaci ty. Idaho Power's 50-year operating license for
12 the three-dam Hells Canyon hydroelectric complex expired
13 on July 31, 2005, and has been renewed annually by the
14 Federal Energy Regulatory Commission (" FERC") pending the
15 outcome of Idaho Power's relicensing application. Absent
16 a new license to continue operating the Hells Canyon
17 Complex, Idaho Power would have to construct new
18 generation facilities or otherwise secure replacement
19 power. Analogous to a retrofit of a coal-fired plant to
20 comply with new air quality standards, over the past ten
21 years, Idaho Power has invested significant amounts to
22 mitigate the externalities associated with the Hells
23 Canyon dams such that the FERC will grant Idaho Power a
24 new operating license.
25
332 MILLER, DI 7
Idaho Power Company
.
.
.
1 THE CURNT CWIP ACCOUNT BACE
2 Q.When did the Company begin incurring Hells
3 Canyon relicensing costs and what types of costs have
4 been included in Account 107?
5 A.The Company began incurring Hells Canyon
6 relicensing costs in 1999. In addition to AFUDC, other
7 costs capitalized in Account 107 with respect to the
8 Hells Canyon relicensing effort include labor, materials,
9 purchased services, and other expenses.
10 Q.How does AFUDC apply to hydro relicensing and
11 why is it capitalized in Account 107?
12 A.Relicensing acti vi ties are financed from
13 internally generated funds and funds raised from external
14 sources including short-term debt, long-term debt, and
15 new equity. As a result, the Company incurs financing
16 costs. The Company is permitted to accrue and capitalize
17 these financing costs to Account 107 as AFUDC during the
18 proj ect period. AFUDC is calculated monthly using a rate
19 followed by the Commission and determined by the FERC
20 formula (CFR 18, Part 101, Subchapter C, Electric Plant
21 Instruction 3 (A) (17), as amended by a FERC letter dated
22 December 30, 1981). Once the construction proj ect is
23 completed, both the construction costs and AFUDC are
24 closed to plant as an asset. Once included in rate base,
25 AFUDC is typically
333 MILLER, DI 8
Idaho Power Company
.
.
.
15
1 recovered over the life of the asset through depreciation
2 expense and a return on investment is earned.
3 Q.What was the December 31, 2007, CWIP balance
4 for Hells Canyon relicensing costs?
5 A.Accumulated Hells Canyon relicensing costs and
6 its AFUDC have been recorded as CWIP in Account 107. As
7 of December 31, 2007, the Hells Canyon relicensing costs
8 included in FERC Account 107 totaled $95.6 million. Of
9 that amount, financing costs as represented by AFUDC were
10 $27.9 million or 29 percent of the total.
11 IDAHO POWER'S PROPOSAL
12 Q.Please describe Idaho Power's proposal to
13 currently recover financing costs (AFUDC) associated with
14 Hells Canyon relicensing.
A.Current Idaho law allows the Company to earn
16 and collect its return on CWIP by including CWIP in base
17 rates.I believe the law's intent is to provide the
18 Company support in the form of cash collections during
19 the proj ect period. Idaho Power's proposal is in line
20 with that intent. At this time, Idaho Power is not
21 requesting the inclusion of CWIP in rate base to
22 currently earn and collect its return. Rather, the
23 Company is requesting payment of estimated financing
24 costs at the same time that they will be incurred in
25 2009. Those collections will
334 MILLER, DI 9
Idaho Power Company
.
.
.
1 offset Hells Canyon plant additions when included in rate
2 base at a future date. Effecti vely, the request allows
3 for the true-up for differences between actual calculated
4 AFUDC and any collections from customers. This proposal
5 simply requests that the Commission allow customers to
6 pay financing costs on Hells Canyon relicensing
7 expendi tures as they occur. As the Company is currently
8 seeking to only recover AFUDC for Hells Canyon
9 relicensing, I believe this proposal is the most simple
10 and straightforward administratively.
11 Q.Why is the Company requesting recovery of AFUDC
12 as it is incurred for Hells Canyon relicensing
13 expendi tures?
14 A. From 1999 through 2007, 'the Company has
15 incurred $ 95.6 million of costs for the relicensing of
16 Hells Canyon. Over those eight years, the Company has
17 been solely responsible for acquiring funds to support
18 relicensing activities and has borne the financing costs
19 of doing so as represented by $27.9 million of
20 accumulated AFUDC captured in Account 107. Although
21 AFUDC is recorded as income for income statement purposes
22 in accordance with GAAP, the Company does not receive
23 cash recovery until the asset becomes a part of rate
24 base. The ongoing growth of AFUDC, as demonstrated later
25 in my testimony, is a serious
335 MILLER, DI 10
Idaho Power Company
.
.
.
1 concern for the Company as it builds to a significant
2 portion of the expected future increase in rate base. By
3 collecting financing costs currently, customers will, in
4 effect, pay those costs as they are incurred and reduce
5 or smooth future rate impacts. For the Company, current
6 cash collection strengthens cash coverage ratios which
7 help to maintain credit strength through a period of
8 significant proj ect spending and facilitate funding for
9 future investment.
10 IDAHO POWER'S REQUEST
11 Q.What amount is the Company requesting for
12 recovery?
13 A. The Company is requesting that $7.6 million be
14 included in base rates to fund the ongoing financing
15 costs associated with the Hells Canyon relicensing
16 project.
17 Q.Why $ 7 . 6 million?
18 A.$7.6 million is the amount needed to offset the
19 anticipated annual growth of AFUDC. That collection will
20 reduce the future rate impact resulting from the eventual
21 inclusion of Hells Canyon relicensing costs in future
22 rate base.
23 Q.Have you prepared or supervised the preparation
24 of an exhibit relating to the collection of financing
25 costs related to Hells Canyon relicensing?
336 MILLER, DI 11
Idaho Power Company
.
.
.
1 A.Yes. I supervised the preparation of Exhibit
2 No. 35.
3 Q.Please describe Exhibit No. 35.
4 A.On December 31, 2007, Hells Canyon relicensing
5 CWIP and associated AFUDC in Account 107 amounted to
6 $ 67. 7 million and $27.9 million respectively. For the
7 projected years 2008 and 2009: (1) no new capital
8 expendi tures were assumed, although additional costs will
9 be incurred; (2) 2008 AFUDC additions were calculated on
10 the total Account 107 balance of $95.6 million for the
11 year ended December 31, 2007, and compounded monthly; (3)
12 2009 AFUDC additions were calculated on the total CWIP
13 balance of $102.8 million for the projected year ending
14 December 31, 2008, and compounded monthly; and (4) AFUDC
15 additions were calculated using the actual 2007 average
16 AFUDC rate of 7.19 percent. Without considering
17 additional future expenditures, it is estimated that 2008
18 and 2009 AFUDC will be $7.1 million and $7.6 million,
19 respectively. By year-end 2009, the total accumulated
20 AFUDC associated with 2007 Account 107 balances will be
21 $42.7 million or 39 percent ($42.7 million divided by
22 $110.4 million) of the total. The Company is requesting
23 the collection of $7.6 million, the 2009 estimated AFUDC.
24
25
337 MILLER, DI 12
Idaho Power Company
1 Q. If the Company is allowed to collect these.2 funds, how would the Company account for them?
3 A.Funds recovered during the Hells Canyon
4 relicensing construction period would be used to set up
5 an Account 254 Regulatory Liability.
6 Q.For rate making purposes, how does the Company
7 propose to treat the Regulatory Liability established
8 wi th funds collected for AFUDC?
9 A.Once the Hells Canyon operating license is
10 recei ved and the Hells Canyon relicensing proj ect is
11 placed in service, the Company will include the accrued
12 costs of the proj ect in rate base. These costs will be.13 reduced by the Account 254 Regulatory Liability.
14 Customers will benefit in two ways. First, customer rates
15 will be lower because they would not pay the required
16 return on what would otherwise be a higher rate base
17 balance. Second, for cost of service purposes, the
18 Regulatory Liability would be amortized over the life of
19 the plant asset. In this manner, the funds collected
20 flow back to the customers.
21 Q.Would there be any change to how actual AFUDC
22 associated with Hells Canyon relicensing is treated for
23 accounting purposes?
24 A.No. Financial accounting for Account 107 would.25 remain the same. New Hells Canyon relicensing
338 MILLER, DI 13
Idaho Power Company
.1 expenditures will continue to be recorded to Account 107.
2 AFUDC would be calculated and capitalized to Account 107
3 following the Company's standard practice.
4 Q.The CWIP balance for Hells Canyon relicensing
5 was $ 95.6 million as of December 31, 2007, of which $27.9
6 million was AFUDC. Why is Idaho Power concerned with the
7 growth in AFUDC?
8 A.As discussed earlier in my testimony, Idaho
9 Power is requesting that $7.6 million of 2009 AFUDC
10 associated with Hells Canyon relicensing be included in
11 base rates. Without this collection and assuming no
12 additional investment, the Hells Canyon CWIP balance is.13 estimated to grow to $110.4 million by year-end 2009.
14 Under these assumptions, the growth is solely due to the
15 continued accumulation of AFUDC which threatens to dwarf
16 other relicensing costs. Over two years, absent my
17 proposal, the Hells Canyon CWIP balance attributable to
18 AFUDC would grow 53 percent from $27.9 million to $42. 7
19 million and represent 39 percent of total Hells Canyon
20 relicensing CWIP balance by year-end 2009.
21 Q.Are there any other reasons why the current
22 collection of financing costs associated with CWIP for
23 Hells Canyon relicensing costs is beneficial for Idaho
24 Power and its customers?.25
339 MILLER, DI 14
Idaho Power Company
.
.
16
17
18
19
20
21
22
23
24.25
1 A. Investments for Hells Canyon relicensing have
2 been accumulating since 1999 and the benefits of
3 obtaining the new operating license are well understood.
4 Because Idaho Power's request estimates the 2009 AFUDC
5 accrual on actual December 31, 2007, CWIP balances for
6 Hells Canyon relicensing, Staff audit and review will be
7 eased and conjecture eliminated. When the operating
8 license is received and the proj ect closes to plant,
9 actual known amounts for expenditures and accrued AFUDC
10 will be included in rate base offset by the known
11 collections for AFUDC. In effect, this becomes a true-up
12 to actual amounts for rate-making purposes.
13 Q.Does this conclude your testimony?
14 A.Yes, it does.
15
340 MILLER, DI 15
Idaho Power Company
.
.
.
1 Q.Please state your name.
2 A.My name is Catherine M. Miller.
3 Q.Are you the same Catherine Miller that
4 presented direct testimony in this proceeding?
5 A.Yes.
6 Q.What issues will you be responding to in your
7 rebuttal testimony?
8 A.As described in my direct testimony on pages
9 5-6, with Commission concurrence, Idaho law now allows
10 the Company an opportunity to earn and collect its
11 authorized return on Construction Work in Progress
12 ("CWIP") by including CWIP in base rates. In Idaho
13
14
Power's 2008 general rate case filing, the Company has
requested that $7.6 million be included in base rates to
15 fund the ongoing financing costs associated with the
16 Hells Canyon relicensing project. The Company
17 appreciates Staff's agreement with the Company that the
18 expense balance associated with the allowance for funds
19 used during construction ("AFUDC") from the Hells Canyon
20 relicensing effort is growing at an alarming rate and
21 that collecting AFUDC related to the Hells Canyon
22 relicensing proj ect in current rates is in the public
23 interest.
24 My rebuttal testimony explains why the Company's
25 methodology for forecasting 2009 AFUDC for Hells Canyon
341 MILLER, DI REB 1
Idaho Power Company
.
.
24.25
1 relicensing better reflects 2009 AFUDC expense
2 expectations than Staff Witness Vaughn's recommended
3 methodology. I will respond to Ms. Vaughn's proposal to
4 accrue interest at the same rate as AFUDC booked as CWIP
5 for financial reporting purposes. I will explain why
6 Staff Witness Vaughn's proposal to stop accruing AFUDC on
7 Hells Canyon relicensing CWIP at December 2009 is both
8 unnecessary and unwise. In response to Dr. Peseau' s
9 testimony, I will discuss the Company's proposed
10 ratemaking treatment for the AFUDC proposal and how it
11 benefits customers.
12 AFC AMOUNT TO BE COLLECTED
13 Q. Staff Witness Vaughn recommends on page 4 of
14 her testimony that the Commission deny $2,881,849 of the
15 Company's proposed collection of AFUDC associated with
16 financing the Hells Canyon relicensing CWIP. What is
17 your understanding of the basis for this proposed denial?
18 A.Ms. Vaughn's testimony confirms that Staff
19 essentially agrees with the Company that collecting Hells
20 Canyon relicensing AFUDC in the base rates established in
21
22
23
342 MILLER, DI REB 2
Idaho Power Company
.
.
1 this case is in the public interest. Ms. Vaughn's
2 adj ustment is the result of using a different approach
3 than the Company's to estimate the amount to be included
4 in base rates.
5 Q.Do you agree with Ms. Vaughn's recommended
6 adj ustment?
7 A.No. Two items drive Ms. Vaughn's adj ustment to
8 the Company's methodology:(1) Ms. Vaughn's selection of
9 the time period used to estimate the 2009 AFUDC rate and
10 (2) Ms. Vaughn's approach to extending the resulting
11 AFUDC amount to 2009. Neither item provides an accurate
12 estimate of 2009 AFUDC expenses.
13 Q. Please describe the method Ms. Vaughn used to
14 forecast the AFUDC rate for 2009.
15 A.As described on page 15 of her testimony, Ms.
16 Vaughn has proposed using the average of January 2008
17 through August 2008 actual AFUDC rates to proj ect a
18 December 2008 AFUDC amount equal to $396,191. Staff then
19 multiplied that $396,191 amount by twelve to create a
20 forecast AFUDC amount of $4,754,292 for 2009. The
21 Company requested that $7.6 million be included for 2009.
22 Q.Why do you believe Staff Witness Vaughn's
23 method of forecasting the appropriate AFUDC rate is
24 incorrect?.25
343 MILLER, DI REB 3
Idaho Power Company
.
.
.25
1 A.Staff's calculation is inappropriate for three
2 reasons. First, by using only January 2008 through
3 August 2008 AFUDC rates, Staff's methodology has not
4 appropriately captured the impact on AFUDC rates of
5 changing short term debt balances. These changes are due
6 to the seasonality of cash flows and the timing of long
7 term debt issuances. Second, by using less than a full
8 year's data, Staff's methodology fails to recognize the
9 increases in borrowing costs that have occurred since
10 August as a result of the current financial crisis. This
11 failure to recognize current conditions is a critical
12 flaw in the Staff's proposed AFUDC rate assumption.
13 Finally, Staff's methodology ignores the compounding
14 issue that both Staff and the Company agree is of
15 concern. i will discuss the compounding issue in greater
16 detail later in my rebuttal testimony.
17 Q.How are AFUDC rates determined?
18 A.The actual AFUDC rate is calculated using a
19 rate methodology followed by the Idaho Commission. This
20 rate is determined by applying a formula developed and
21 approved by the FERC.(CFR 18, Part 101, Subchapter C,
22 Electric Plant Instruction 3 (A) (17), as amended by a FERC
23 letter dated December 30, 1981). Because the FERC
24 formula includes average short term debt balances and
interest
344 MILLER, 01 REB 4
Idaho Power Company
.
.
20
21
22
23
24.25
1 rates in its calculation, the resulting AFUDC rate is
2 impacted by changing short term borrowing balances
3 resul ting from such things as short term cash needs for
4 net power supply expenses or from the timing of long term
5 debt or equity issuances that are necessary to support
6 construction expenditures.
7 Q.What are the AFUDC rates for 2008 through
8 October 2008?
9 A.The following schedule lists the AFUDC rates
10 used in Ms. Vaughn's calculation, the AFUDC rates that
11 were in effect through October 2008, the average short
12 term debt balances used for calculating AFUDC rates, and
13 the related short term debt rates.
14
15
16
17
AFUC Rate Average Short
used by AFUC Rate Term DebtStaffin Effect ($millions)
Jan-08 6.352%6.352%$140.9
Feb-08 5.592%5.592%$151.0
Mar-08 4.111%4.111%$177.0
Apr-08 4.136%4.136%$196.0
May-08 3.696%3.696%$200.6Jun-08 3.016%3.016%$209.5Jul-08 4.894%4.894%$148.2
Aug-08 6.276%6.271%$82.1
Sep-08 4. 759%6.240%$100.7
Oct-08 4.759%6.585%$159.3
Nov-08 4.759%Na Na
Dec-08 4. 759%Na Na
5.0%
4.0%
3.5%
3.3%
3.2%
3.0%
3.2%
3.3%
4.1%
6.1%
Na
Na
Short Term
Debt Rate
18
19
345 MILLER, DI REB 5
Idaho Power Company
.
.
.
1 Q.What does this chart portray regarding changes
2 in the AFUDC rates?
3 A.This chart demonstrates how current operating
4 condi tions and the timing of long term debt or equity
5 issuances impact average short term debt balances which
6 in turn impacts the AFUDC rate.Increasing short term
7 debt balances and low short term debt rates caused the
8 downward trend in the AFUDC rate from January 2008
9 through June 2008. As stated in the Company's September
10 30, 2008, 10Q filed with the SEC, Idaho Power issued $120
11 million of its 6.025 percent First Mortgage Bonds,
12 Secured Medium-Term Notes, Series H, due July 15, 2018,
13 on July 10, 2008. Idaho Power used the net proceeds of
14 that issuance to pay down short term debt. As a result,
15 the AFUDC rates began rising in July. As noted in Mr.
16 Steve Keen's rebuttal testimony on page 8, the Company
17 has experienced significant increases in commercial paper
18 rates. Rates increased from roughly 3 percent in the
19 summer to more than 6 percent in October. By October
20 2008, the effective AFUDC rate equaled 6.585 percent.
21 Q.Considering current conditions, is it
22 appropriate to use the average of January 2008 through
23
24
25
346 MILLER, DI REB 6
Idaho Power Company
.
.
.
1 August 2008 AFUDC rates (4.759 percent), as Staff has
2 done, to forecast 2009 AFUDC on Hells Canyon relicensing
3 CWIP?
4 A.No. The AFUDC rate used for forecasting 2009
5 should be a rate that is expected to be in place at the
6 time rates are in effect. By using a partial year for
7 proj ections, Staff has not appropriately captured the
8 impact of changing short term debt balances due to the
9 seasonali ty of cash flows and the timing of long term
10 debt issuances and increasing costs of short term debt.
11 As a result, Staff's estimated AFUDC rate calculated at
12 4. 759 percent based on the average of the first eight
13 months of 2008 is too low.
14 Q. What AFUDC rate do you support for forecasting
15 2009 AFUDC?
16 A.I continue to support the AFUDC rate presented
17 in my original testimony, which was the average 2007
18 AFUDC rate of 7.19 percent. This rate is a reasonable
19 estimate of the AFUDC rate to be used for 2009 as it uses
20 a full year in its determination.
21 Q.Putting the selection of the appropriate AFUDC
22 rate aside, do you agree with the methodology Staff used
23 to calculate 2009 estimated AFUDC?
24
25
A.No. On page 15 of her direct testimony, Ms.
Vaughn describes Staff's methodology used to estimate
2009
347 MILLER, DI REB 7
Idaho Power Company
.
.
.
1 AFUDC. Beginning with December 31, 2007, Hells Canyon
2 CWIP balances, Staff calculates the monthly AFUDC amount
3 then adds it to the CWIP balance to calculate the
4 following month's AFUDC. This is commonly referred to as
5 "compounding. " Staff proceeds in this manner through
6 December 2008. To project the 2009 AFUDC amount, Staff
7 simply takes the proj ected December 2008 AFUDC dollar
8 amount and multiplies it by twelve. By following this
9 methodology , effectively, Staff has ignored the
10 compounding of 2009 AFUDC that both Staff and the Company
11 agree is of concern.
12 STOPPING AFUDC IN DECEMBER 2009
13 Q. Do you agree with Staff's proposal to stop
14 calculating and accruing AFUDC on Hells Canyon
15 relicensing costs at the end of December 2009?
16 A.No. The Company disagrees with Staff's
17 proposal to stop AFUDC for the following reasons. First,
18 Ms. Vaughn's proposal is the result of her incorrect
19 conclusion that the Company is incented to slow down the
20 relicensing process in order to accrue more AFUDC. The
21 fallacy of that argument is demonstrated by Ms. Vaughn's
22 direct testimony. She points out on page 18 that the
23 Company has little direct control over when FERC will
24 issue a permanent license; therefore, the existence of
25 any
348 MILLER, DI REB 8
Idaho Power Company
.
.
.
1 theoretical incentive or disincentive to slow things down
2 or speed them up is irrelevant. Finally, if accrual of
3 AFUDC were to stop on December 2009, as Ms. Vaughn
4 proposes, and the Company has not received the permanent
5 license from FERC necessary to close the proj ect to plant
6 in service and include its cost in rate base, the Company
7 will be denied the opportunity to earn a fair, just, and
8 reasonable return on its investment.
9 Q.Why wouldn't the Company be incented to delay
10 completion of the Hells Canyon relicensing project if the
11 AFUDC accrual continued past December 2009?
12 A.The Company is highly motivated to complete
13 this proj ect and begin recovering what has become an
14 extraordinarily large investment balance. As of December
15 31, 2007, Hells Canyon relicensing costs recorded in CWIP
16 equaled $ 95.6 million. The Company has continued to
17 incur relicensing costs and as of October 31, 2008, the
18 CWIP balance equaled $103.3 million. It is important to
19 remember that accrued AFUDC does not provide the Company
20 with cash to pay its bills. As a result, Idaho Power is
21 quite eager to include this large sum in rate base as
22 soon as possible given that the Company has funded this
23 relicensing effort since 1999 without reimbursement.
24
25
349 MILLER, 01 REB 9
Idaho Power Company
.
.
.
1 That said, it is important not to lose sight of the
2 fact that in this case, the Company is only asking to
3 collect estimated 2009 AFUDC financing costs and is not
4 seeking to recover its original investment at this time.
5 The collection of 2009 AFUDC will be recorded as a
6 Regulatory Liability and, therefore, does not contribute
7 to the Company's profi tabili ty. Rather, it provides cash
8 flow to improve cash flow coverage ratios that are
9 necessary to maintain Idaho Power's credit strength and
10 its ability to access external markets for funding
11 construction acti vi ties.
12 Q.In Ms. Vaughn's response to Idaho Power's
13 Production Request No. 34, she asserts that the Company
14 will experience "enhanced" cash flows because the AFUDC
15 included in rates will be grossed up for taxes. Is she
16 correct?
17 A.No. This is simply not true. The resulting
18 tax expense will be deferred so as to have a zero impact
19 on the Company's income statement; however, the Company
20 will currently pay income taxes on the amount collected.
21 Q.Can the Company predict with certainty when
22 FERC will issue a permanent license?
23 A.No. The Company agrees with Ms. Vaughn that
24 the Company has little direct control of when a permanent
25
350 MILLER, DI REB 10
Idaho Power Company
.
.
1 FERC license will be received. The FERC licensing
2 process is extraordinarily complex both in its scope and
3 large number of participants. In addition, the recent
4 change in the administration at the national level may
5 prolong the process even further. Although Ms. Vaughn
6 states that a permanent license could be received as
7 early as January 2009, the Company does not believe a
8 permanent FERC license could be received prior to January
9 2010. Because the Company has little direct control over
10 when the permanent license is received (and thus when
11 AFUDC accrual would naturally be stopped according to
12 generally accepted accounting principles ("GAAP")) , it
13 does not matter whether or not there is any theoretical
14 disincenti ve to complete the proj ect.
15 Q.Please elaborate on your prior statement that
16 if accrued AFUDC on Hells Canyon relicensing were stopped
17 at December 2009, the Company will not have an
18 opportunity to earn a fair, just, and reasonable return.
19 A.While I am not an attorney, my understanding of
20 Idaho Code § 61-502A is that absent a finding that CWIP
21 recovery is in the public interest, the Commission must
22 allow the Company to accrue a just, fair, and reasonable
23 AFUDC computed in accordance with GAAP. As discussed in
24 my direct testimony, in this case Idaho Power is not.25
351 MILLER, DI REB 11
Idaho Power Company
.
.
.
1 requesting the inclusion of CWIP in rate base to
2 currently earn and collect its return. Rather, the
3 Company is requesting that it be given the opportunity to
4 recover estimated financing costs at the same time they
5 are expected to be incurred in 2009. This collection
6 would be recorded as a Regulatory Liability. The Company
7 "earns" its return through the accrual of AFUDC on Hells
8 Canyon relicensing CWIP. If accrued AFUDC were stopped
9 on December 2009 as Ms. Vaughn proposes and the Company
10 had not yet received a permanent license from FERC
11 necessary to close the project and include it in rate
12 base, the Company will not have an opportunity to earn a
13 fair, just, and reasonable return. My attorney advises
14 me that this could result in an unlawful taking of assets
15 to which the Company is entitled. Such a result would be
16 particularly egregious given the $103.3 million Idaho
17 Power has spent on Hells Canyon relicensing thus far.
18 CACULTION OF ACCRUED INTEREST
19 Q.Do you agree with Staff's proposal to accrue
20 interest on the Regulatory Liability at the same rate as
21 AFUDC is recorded as CWIP for financial accounting
22 purposes?
23 A.Partially. The Company agrees that accruing a
24 carrying charge based on the same rate as AFUDC is
25
352 MILLER, 01 REB 12
Idaho Power Company
.1 recorded as CWIP for financial accounting purposes is
2 reasonable in this instance. The Company agrees with Ms.
3 Vaughn that the most appropriate rate is the actual AFUDC
4 rate used for financial accounting purposes. However, to
5 properly match the AFUDC accrued on CWIP, the balance on
6 which the carrying charge is calculated must contain all
7 components that would be included in rate base, including
8 tax accounts. In this manner, the results would match
9 the compounded AFUDC accrued for CWIP purposes.
10 Q.Do you agree with Dr. Peseau' s assertion that
11 if the Commission accepts your proposal for recovering
12 2009 AFUDC, customers would only get a "Regulatory Asset".13 amortized over the life of the plant asset which amounts
14 to a 30 year unsecured loan at 0 percent interest?
15 A.No. Dr. Peseau apparently does not completely
16 understand what I am proposing. First, the collection of
17 AFUDC would not be recorded as a "Regulatory Asset" as
18 Dr. Peseau states. In my direct testimony on page 13, I
19 discuss the Company's proposed regulatory treatment. The
20 Company proposes that the collection of AFUDC would be
21 recorded as a Regulatory Liability. When the Company
22 requests that the Hells Canyon relicensing proj ect be
23 placed in rate base, the associated Regulatory Liability
24 will be included as a reduction to rate base..25
353 MILLER, DI REB 13
Idaho Power Company
.
.
.
1 Q.Dr. Peseau characterizes your proposal as an
2 unsecured loan at 0 percent interest from customers to
3 the Company.Is that an accurate description of how your
4 proposal would operate?
5 A.No. Using the "loan" analogy, a more accurate
6 way to describe what the Company is recommending is that
7 customers pay estimated "interest" costs as they are
8 being incurred. As a result, the eventual final "loan"
9 balance (future rate base) is lower, thereby reducing
10 customers' future "interest" and "principal" payments for
11 the rate base asset. Analogous to ratemaking, the
12 benefit can clearly be seen with an example of a consumer
13 loan.
14 In this example, assume a consumer borrows $100.00
15 at 8 percent. The term of the loan is for 10 years but
16 the consumer is not required to begin paying back the
17 loan until 5 years have passed. The consumer is then
18 given the choice of paying interest costs as they are
19 incurred or paying interest costs when principle payments
20 begin. As is demonstrated below, if the consumer pays
21 the interest as it is incurred, the consumer's total
22 payments equal $165.23 or $18.77 lower than the $184.00
23 he would have otherwise paid.
24
25
354 MILLER, DI REB 14
Idaho Power Company
1.2
3
4
5
6
7
8
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
--
Paying Interest as Delaying Interest
Incurred Payments
Interest Interestatat
Payments 8 percent Balance Payments 8 percent Balance
Year 0 100. 00 100. 00
Year 1 (8.00)8. 00 100. 00 8. 00 108. 00
Year 2 (8. 00)8. 00 100.00 8.64 116.64
Year 3 (8.00)8. 00 100. 00 9.33 125.97
Year 4 (8.00)8. 00 100. 00 10 .08 136.05
Year 5 (8.00)8. 00 100.00 10 .88 146.93
Year 6 (25.05)8. 00 82.95 (36.80)11. 75 121. 89
Year 7 (25.05)6.64 64.55 (36.80)9.75 94.84
Year 8 (25.05 )5.16 44.66 (36.80)7.59 65.62
Year 9 (25.05)3.57 23.19 (36.80)5.25 34.07
Year 10 (25.05)1. 86 O. 00 (36.80)2.73 0.00
Total
Payment ($165.23)($184. 00)
Q. Does this conclude your rebuttal testimony?
A. Yes, it does.
355 MILLER, DI REB 15
Idaho Power Company
.
.
.
1
2 open hearing.)
(The following proceedings were had in
MS. NORDSTROM: I make this witness
4 available for cross-examination.
3
5
6 do you have any questions?
COMMISSIONER SMITH: Thank you. Mr. Ward,
7
8
9
10
11 BY MR. WARD:
12 Q
MR. WARD: I do, thank you.
CROSS-EXAMINATION
Ms. Miller, I'm principally interested in
13 your rebuttal testimony, if you would turn to page 13.
A
Q
Yes.
Now, at lines 10 through 24, there's a
17 question and answer in which you're asked whether you
14 Are you there?
18 agree with Dr. Peseau' s assertion that in the event CWIP
15 A
16 Q
19 is granted, the customers would get a regulatory asset.
20 Now -- and you say no, that it's in fact a regulatory
21 liabili ty. In fact, though, it's a regulatory liability
22 on the Company's books; correct?
23
24
25
Yes, it is.
And when Dr. Peseau used the words
regulatory asset that the customers would get, he put it
CSB REPORTING
[phone]
356 MILLER (X)
Idaho Power Company
.
.
.25
1 in quotes; correct?
2 A I believe he did, yes.
3 Q Okay, and isn't ita fact that when
4 customers pay for CWIP, what happens is they give to the
5 Company whatever amount of money, in this case we're
6 talking about $ 7.6 million; correct?
7 A Yes.
8 Q They pay that before the plant is placed
9 in service and when the plant is placed in service, then
10 the Company takes the regulatory liability that they've
11 recorded, that it's recorded, the $7.6 million, and
12 deducts it from the plant, the plant cost; correct?
13 A Yes.
14 Q Now, isn't it true that the only way that
15 gets returned to the customers is over whatever
16 depreciable life that plant has? In the case of a
17 long- li ved plant like Hells Canyon, that can be 30 years;
18 correct?
19 A Yes.
20 Q Okay; so isn't the characterization of
21 this correct, that in fact the customers have a
22 regulatory asset that will be returned to them, repaid to
23 them, if you will, over 30 years or whatever the
24 depreciable life turns out to be?
A Right. Where -- oh.
CSB REPORTING
[phone]
357 MILLER (X)
Idaho Power Company
.
.
.25
1 Q Now, Ms. Miller, if I'm a customer who has
2 cash flow concerns well, let me back up, and the
3 argument on behalf of CWIP, as I take it, is that it's
4 two-fold and if you wish to put this off on Mr. Gale,
5 I will understand, but if you are up to answering, go
6 ahead and answer. Basically, the argument is two-fold:
7 One, that it will smooth the customer payments, if you
8 will, and rate impacts; and secondly, that it increases
9 the Company's cash flow; is that your basic
10 understanding?
11 A Yes, that is.
12 Q Now, if I'm a customer with cash flow
13 problems of my own, why am I interested in this deal?
14 A Well, where I am the technical witness in
15 the accounting and in the numbers, I don't feel like I
16 can respond to what a customer would think or feel.
17 Q All right; so you'd rather I ask that of
18 Mr. Gale, I guess?
19 A I believe so.
20 MR. WARD: All right, I'll wait for
21 Mr. Gale. Thank you.
22 COMMISSIONER SMITH: Thank you, Mr. Ward.
23 Mr. Olsen.
24 MR. OLSEN: No questions.
COMMISSIONER SMITH: Mr. Purdy.
CSB REPORTING
[phone]
MILLER (X)
Idaho Power Company
358
.
.
.
1 MR. PURDY: I have none. Thank you.
2 COMMISSIONER SMITH: Mr. Richardson.
3 MR. RICHARDSON: No questions,
4 Madam Chair.
5 COMMISSIONER SMITH: I see Mr. Miller has
6 left us. Do you have any questions?
7 MR. BRUDER: No questions.
8 COMMISSIONER SMITH: Okay, Mr. Price.
9 MR. PRICE: I do have a couple of
10 questions. Thank you, Madam Chair.
11
12
13 CROSS-EXAMINATION
14
15 BY MR. PRICE:
16 Q Ms. Miller, I think you testified earlier
17 that the effect of including AFUDC and the associated tax
18 gross-up would be to increase the Company's cash flow;
19 correct?
20
21
A Yes.
Q Okay, and can you please describe what
22 types of items the Company could put into place that
23 would allow it to defer its taxes? Items -- I'll restate
24 that question. What types of utility plant or
25 transmission or other such items could the Company put in
CSB REPORTING
[phone]
359 MILLER (X)
Idaho Power Company
.
.
.
1 place that would allow it to defer its taxes?
2 A I'm still not following your question.
3 Q In what instance does the Company defer
4 taxes on its books?
5 A Let me describe this proposal a little bit
6 further. In this proposal, what we are doing, we are
7 asking for the collection and the reserve, the collection
8 of AFUDC associated with CWIP. We're not in this case
9 asking for CWIP to be in rate base where we both earn and
10 collect AFUDC. What this proposal is is we're requesting
11 the collection of AFUDC. When that cash comes in along
12 with the gross-up, when that cash comes in, we must
l3 currently pay taxes on that cash. At that time a
14 deferred tax asset is set up, and when I mean deferred,
15 it doesn't mean that it's deferred for cash purposes.
16 What it means is that with this proposal, there's no
17 income statement impact in this proposal. There is no
18 addi tional earnings. We simply defer on the income
19 statement those taxes and we set up a deferred tax
20 asset.
21 MR. PRICE: I don't have any further
22 questions.
23 COMMISSIONER SMITH: Commissioner
24 Redford.
25 COMMISSIONER REDFORD:I just have a
CSB REPORTING
[phone]
360 MILLER (X)
Idaho Power Company
.
.
.
1 couple of questions about the accounting.
2
3 EXAMINATION
4
5 BY COMMISSIONER REDFORD:
6 Q How do you account for the plant? Is it
7 on the basis of, which you'll defer, is it on the basis
8 of that as you draw down on a short-term construction
9 loan, take for instance, do you then defer the costs on a
10 draw-down basis; that is, whenever you need the money to
11 pay for a portion of the construction, is that the point
12 that it's deferred?
13 A Are you referring to plant accounting?
Q Yes.
A How this CWIP is working?
Q Yes.
A No,how we finance our CWIP is through
14
15
16
17
18 internally-generated funds and different aspects of
19 either long-term debt or equity and so that is what
20 supports our construction programs as we build CWIP,
21 whether it be relicensing or any other plant item that
22 we're constructing, so, no, there isn't something
23 separately set up for it.
24
25
Q Do you take the estimate of the plant at
that time, the total plant, estimated total plant, at
CSB REPORTING
[phone]
361 MILLER (Com)
Idaho Power Company
.
.
.
1 that time do you then begin charging customers the total
2 amount or is it spent?
3 A It is as we construct, as this CWIP item
4 grows and as we construct, the Company is solely
5 responsible for providing any financing associated with
6 it, so in the case of Hells Canyon where we've spent to
7 date, as of October, 103 million, the Company has had
8 sole responsibility of that cash outflow. The only time
9 the Company gets cash at this point coming in is when
10 that plant item is closed and placed in rate base and
11 then that's when we start earning our return on that
12 investment and also the return of the investment itself.
13 That's when the cash comes in.
14 Q Okay, take Hells Canyon, for example, if
15 we were just starting over on the licensing and we agreed
16 to this CWIP proposal, would you start charging customers
17 based upon the total you estimate the cost or are you
18 charging the customers as the money is spent?
19 A Right. In this case in the Company's
20 proposal, what we've done is we've estimated what AFUDC
21 is likely to be in 2009 so that the balance of the actual
22 construction or what's in CWIP in relicensing, it was
23 based on 12/31/2007 balances, so this is not about the
24 plant item itself, it's about matching and collecting
25 financing costs at the same time that we expect them to
CSB REPORTING
[phone]
362 MILLER (Com)
Idaho Power Company
.
.
1 occur, so it is just the financing cost, the AFUDC.
2 Q Well, you don't include the entire
3 estimate of the cost?
4 A What we've included is the estimate of the
5 CWIP cost as of 12/31/2007 and through this year we've
6 continued to spend and appropriately capitalize
7 relicensing costs to CWIP, so actual proj ect costs are
8 continuing to go up, so I believe the answer is no, it's
9 just based, the estimate of the AFUDC is just based, on
10 plant costs as of 12/31/07. We're not asking to recover
11 those costs in this proceeding.
12 COMMISSIONER REDFORD:Okay, I have no
13 further questions.
14 COMMISSIONER SMITH: Do you have any
15 redirect, Ms. Nordstrom?
16 MS. NORDSTROM: Yes.
17 MR. WARD: Madam Chair?
18 COMMISSIONER SMITH: Yes, Mr. Ward.
19 MR. WARD: I think the witness may have
20 unintentionally misled Commissioner Redford in response
21 to his questions. May I ask another question or two?
22
23
24.25
COMMISSIONER SMITH: Certainly.
CSB REPORTING
[phone]
363 MILLER (Com)
Idaho Power Company
.
.
.
18
19
20
1 CROSS-EXAMINATION
2
3 BY MR. WARD:
4 Q Ms. Miller, in the accounting, let's say
5 we get away from this particular instance, let's talk
6 about just a generic $100 million plant and let's say
7 that you ask for and are granted recovery of CWIP in the
8 amount of $10 million. In order to account for that, you
9 don't actually make an accounting entry at the time
10 deducting that $10 million from the plant, do you? You
11 put that $10 million in your regulatory liability?
12 A Yes, you put it -- yes.
13 Q And then only when the plant comes on line
14 does that regulatory liability get transferred over and
15 reduce the amount from 100 million to 90 million;
16 correct?
17 A Yes.
MR. WARD: Thank you. That's all I had.
COMMISSIONER REDFORD: Thank you.
21 Now Ms. Nordstrom.
COMMISSIONER SMITH: Thank you, Mr. Ward.
22
23
24
25
MS. NORDSTROM: Thank you.
CSB REPORTING
[phone]
364 MILLER (X)
Idaho Power Company
.
.
.
1 REDIRECT EXAMINATION
2
3 BY MS. NORDSTROM:
4 Q Ms. Miller, just to clarify the question
5 about deferred taxes that the Staff's attorney raised,
6 will customers be held neutral for the tax effects of
7 your proposal over the life of the transaction that
8 you're proposing here?
9 A Yes. Deferred taxes, another name for
10 them are temporary differences, they reverse over time,
11 so it is net zero.
12 MS. NORDSTROM: Thank you. I have no
13 further questions.
14 COMMISSIONER SMITH: Thank you. Thank
15 you, Ms. Miller.
16 (The witness left the stand.)
17 MR. WALKER: Idaho Power calls as its next
18 wi tness Celeste Schwendiman as its next witness.
19
20
21
22
23
24
25
CSB REPORTING
[phone]
365 MILLER (Di)
Idaho Power Company
.
.
.
1 CELESTE SCHWENDIMAN,
2 produced as a witness at the instance of the Idaho Power
3 Company, having been first duly sworn, was examined and
4 testified as follows:
5
6 DIRECT EXAMINATION
7
8 BY MR. WALKER:
9 Q Could you please state your name and spell
10 your last name for the record?
11 A My name is Celeste Schwendiman,
12 S-c-h-w-e-n-d-i-m-a-n.
13 Q And by whom are you employed and in what
14 capacity?
15 A I'm employed by Idaho Power Company. I'm
16 a senior pricing and regulatory analyst.
17 Q And are you the same Celeste Schwendiman
18 that filed direct testimony consisting of 25 pages on
19 June 27th, 2008, as well as your prepared exhibits, No.
20 36 through 46?
21
22
A Yes.
Q Do you have any corrections or changes to
23 your testimony or exhibits?
24
25
A No.
Q If I were to ask you the questions set out
CSB REPORTING
[phone]
366 SCHWENDIMAN (Di)
Idaho Power Company
.
.
.
17
18
19
20
21
22
23
24
25
1 in your prefiled testimony, would your answers be the
2 same here today?
3 A Yes.
4 MR. WALKER: I move that the prefiled
5 direct as well as the Exhibits 36 through 46 of
6 Ms. Celeste Schwendiman be spread upon the record as if
7 read.
8 COMMISSIONER SMITH: If there's no
9 obj ection, we will spread the prefiled testimony upon the
10 record as if read and identify Exhibits 36 through 46.
11 (The following prefiled direct testimony
12 of Ms. Celeste Schwendiman is spread upon the record.)
13
14
15
16
CSB REPORTING
[phone]
367 SCHWENDIMAN (Di)
Idaho Power Company
.
.
.
16
1 Q.Please state your name and business address.
2 A.My name is Celeste Schwendiman. My business
3 address is, 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what capacity?
5 A.I am employed by Idaho Power Company (the
6 "Company") as a Senior Pricing and Regulatory Analyst.
7 Q.Please describe your recent educational
8 background.
9 A.I hold a Master's degree in Business
10 Administration from Northwest Nazarene Uni versi ty. I
11 have also attended the Center for Public Utilities and
12 National Association of Regulatory Utility Commissioners'
13 Practical Skills for a Changing Utility Environment,
14 Current Issues conferences, and the Edison Electric
15 Insti tute' s Electric Advanced Rate Course.
Q.Please describe your work experience with Idaho
17 Power Company.
18 A.I became employed by Idaho Power Company as a
19 Research Assistant II in the Pricing & Regulatory
20 Services Department and was promoted to the level of
21 Senior Pricing and Regulatory Analyst.I sponsored
22 testimony in the Company's last four PCA filings, in the
23 Company's last two general rate cases, and in the
24 Company's filing to
25
368 SCHWENDIMAN, DI 1
Idaho Power Company
.
.
.
1 request recovery of the Telocaset (a. k. a Horizon Wind)
2 power purchase expense.
3 Q.What is the scope of your testimony in this
4 proceeding?
5 A.I am sponsoring testimony in this proceeding on
6 the Idaho Jurisdictional Revenue Requirement resulting
7 from the Jurisdictional Separation Study ("JSS"). My
8 testimony will summarize the adjustments to the total
9 system test year data used by the Company for purposes of
10 restating the Company's rate base, revenues, and expenses
11 for the twelve months ending December 31, 2008.
12 Q.Have you prepared exhibits for this proceeding?
13 A.Yes. I am offering the following exhibits:
14 Exhibit No. 36, Summary of Total Rate Base and
15 Net Income Adj ustments;
16 Exhibit No. 37, Summary of Adjustments _
17 Electric Plant in Service;
18 Exhibi t No. 38, Summary of Adj ustments -
19 Accumulated Provision for Depreciation & Amortization;
20 Exhibit No. 39, Summary of Adjustments _
21 Addi tions & Deletions to Rate Base;
22 Exhibi t No. 40, Summary of Adj ustments -
23 Operating Revenues;
24
25
369 SCHWENDIMAN, DI 2
Idaho Power Company
.
.
.
1 Exhibit No. 41, Summary of Adjustments -
2 Operation & Maintenance Expenses;
3 Exhibi t No. 42, Summary of Adj ustments -
4 Depreciation & Amortization Expense;
5 Exhibi t No. 43, Summary of Adj ustments - Taxes
6 Other than Income Taxes;
7 Exhibit No. 44, Summary of Adjustments -
8 Regulatory Debits and Credits;
9 Exhibit No. 45, Summary of Adjustments - Income
10 Taxes; and
11 Exhibi t No. 46, Jurisdictional Separation
12 Study - Idaho Revenue Requirement.
13 Q.Please describe Exhibit No. 36.
14 A.Exhibi t No. 36 consists of two pages and is a
15 summary of the development of the adj usted total electric
16 system rate base and the development of net income for
17 the test year (twelve months ending December 31, 2008.)
18 The first set of data, displayed in column three of
19 Exhibit No. 36, are the unadjusted 2007 historical,
20 actual results of operations. The adj ustments proposed
21 by the Company for purposes of developing the 2008
22 adjusted total electric system combined rate base and net
23 income are shown in columns 4 through 14 with the total
24 system adjusted test year rate base, expenses, and
25 revenues summarized in column
370 SCHWENDlMAN, 01 3
Idaho Power Company
.
.
.
1 15. The columns are as follows:
2 1 )Column 4, titled: "NORM ADJ"
3 contains the Company's typical test year normalizing
4 adj ustments for the 2007 actual results;
5 2)Column 5, titled: "OTHER ADJ"
6 contains regulatory adjustments that should be applied to
7 the 2007 actual results prior to applying methods to
8 adjust to 2008 levels;
9 3 )Column 6, titled: "2007 BASE" is the
10 adjusted base to which the methods (to create a 2008 test
11 year) were applied;
12 4 )Columns 7-9, titled: "METHODS OF
13 ADJUSTMENT FROM 2007 BASE TO 2008 BASE," and subtitled:
14 "3-YEAR," "5-YEAR," and "OTHER," contain the various
15 methods from the Methods Manual (sponsored in this case
16 by Ms. Smith) that were used to adjust from the 2007 base
17 to a 2008 base. Column 10 includes the resulting dataset
18 once the various methods were applied;
19 5)Column 11, titled: "K&M ADJ" are
20 known and measurable adjustments that will occur in 2008,
21 and column 12 is the result of applying these
22 adj ustments; and
23 6 )Columns 13 through 15 provide the
24 development of the 2008 test year, starting with the
25 adjusted 2008 as found in Column 12.
371 SCHWENDIMAN, DI 4
Idaho Power Company
.
.
.
1 a)Column 13 includes standard
2 normalizing adj ustments;
3 b)Column 14 includes both annualizing
4 and other adj ustments; and
5 c)Column 15 is the resulting dataset
6 for the 2008 test year (twelve months ending December 31,
7 2008) .
8 The test year values, except as otherwise
9 noted, were provided by Ms. Smith.
10 Page one of Exhibit No. 36 summarizes the
11 development of rate base components for the twelve months
12 ending December 31, 2008. The total combined rate base,
13
14
based on actual, unadjusted 2007 results was
$1,992,757,816 (column 3, line 62). After adjustment,
15 the total combined rate base increases to $2,265,781,563
16 (column 15, line 62).
17 Page two of Exhibit No. 36 includes the
18 development of the total system net income for the twelve
19 months ending December 31, 2008. Operating revenues are
20 summarized on line 68. Total operating expenses are
21 summarized on line 79.
22 Q.What is the source of the total year 2007 rate
23 base, expenses, and revenues found in column three of
24 Exhibit No. 36?
25
372 SCHWENDIMAN, 01 5
Idaho Power Company
.
.
.
1 A.Total unadjusted 2007 actual results are
2 presented in column three of Exhibit No. 36, and were
3 provided by Ms. Smith.
4 Q. Why have the 2007 actual results for rate base,
5 revenues, and expenses been adjusted?
6 A. The 2007 actual results were adjusted to
7 reflect known changes that will occur during the 2008
8 test period. Under this proposal, rates will reflect the
9 most current cost information available at the time they
10 become effective.
11 Q.Please explain what types of adj ustments were
12 made for the development of the Idaho jurisdictional
13 revenue requirement.
14 A. Four types of adjustments were made for the
15 development of the Idaho jurisdictional revenue
16 requirement. First, normalizing adjustments were made to
17 the Net Power Supply Cost items which are influenced by
18 weather. Normalizing adj ustments are shown in columns 4
19 and 13 of Exhibit No. 36.
20 Second, annualizing adjustments were made to
21 reflect changes that occur wi thin the test year, but need
22 to be incorporated for the full year. Annualizing
23 adjustments are shown in column 14 of Exhibit No. 36.
24
25
373 SCHWENDIMAN, DI 6
Idaho Power Company
.
.
.
20
1 Third, other types of adj ustments, such as
2 those resulting from past Commission Orders, were used in
3 developing the test year. These types of adj ustments are
4 shown in column five of Exhibit No. 36.
5 Fourth, adjustments to derive a 2008 test year,
6 based on 2007 data, were applied using the methodologies
7 described by Ms. Smith in her testimony. These
8 adjustments are presented in columns 7 through 12 of
9 Exhibit No. 36.
10 Q.Please discuss the normalizing adjustments to
11 the rate base components summarized in Exhibit No. 36,
12 pages one and two, columns 4 and 13.
13 A. The normalizing adjustments that were applied
14 to the rate base fuel inventory, to reflect normalized
15 operating criteria, resulting in required coal
16 inventories at Bridger, Valmy, and Boardman were:(1) a
17 decrease of $1,652,153 for 2007 and (2) an additional
18 decrease of $1,017,979 for 2008. Mr. Said provided these
19 adjustments.
Q.Please discuss the annualizing adjustments to
21 the rate base components summarized in Exhibit No. 36,
22 page one, colpmn 14.
23 A.An annualizing adjustment of $31,763,726 was
24 made to represent a full year of costs for production
25 plant investment made during the test year period.
Proj ects
374 SCHWENDIMAN, DI 7
Idaho Power Company
1.which were greater than two million dollars and are
2 expected to be on line and serving customers before the
3 end of 2008, were treated as if they had been in place
4 for the entire year. This adj ustment is shown on line
5 48. Similar annualizing adjustments were made for
6 transmission projects ($42,627,160 as shown on line 49)
7 for distribution ($11,842,623 as shown on line 50) and
8 for general plant projects ($5,033,774 as shown on line
9 51). The total annualizing adjustment for the 2008
10 investment is $91,267,283 as shown on line 52.
11 An adjustment of negative $180,628 was made to
12 accumulated provision for depreciation to capture the.13 rate base impact of the annualized adj ustment to
14 depreciation expense, and an adjustment of $408,032 for
15 the accumulated amortization, annualized to the end of
16 2008. Ms. Smith provided these adjustments.
17 Q. Have you included any other adjustments to rate
18 base?
19 A.Yes~ The additional adjustments to rate base
20 shown in Exhibit No. 36, page one, column five are:(1 )
21 a reduction of $1,724,177 to remove all but $1,641,351 of
22 plant held for future use, (2) a reduction of $9,119,906
23 to remove the. pre-paid items that are not traditionally
24 included in test year rate base, and (3) a reduction of.25
375 SCHWENDIMAN, DI 8
Idaho Power Company
.
.
.
1 $85,531 to subsidiary rate base associated with an
2 investment at the Company's Bridger plant. These
3 adjustments were provided by Ms. Smith.
4 Q.Please describe page two of Exhibit No. 36.
5 A.Page two of Exhibit No. 36 shows the
6 development of the adjusted total electric system net
7 income for the twelve months ending December 31, 2008.
8 Q.Please describe the Company's normalizing
9 adjustments to the net income components shown in page
10 two, columns 4 and 13, of Exhibit No. 36.
11 A.The normalizing adjustments in columns 4 and 13
12 were adj ustments to both revenues and expenses to remove
13 the impact of weather and temporary rate adjustments.
14 The first is an adj ustment of negative
15 $45,271,567 (line 66) for 2007 and negative $31,175,830
16 for 2008 to the Company's system opportunity sales
17 revenue. Revenues were also adj usted to reflect the
18 decreased level of opportunity sales associated with the
19 multiple historical water conditions. The second
20 adjustment is a reduction of $43,973,647 for 2007 and an
21 additional reduction of $11,496,718 for 2008 to operation
22 and maintenance expense to reflect a net decrease in fuel
23 and purchase power expense associated with multiple
24 historical water conditions as well as an increase in
25 Qualifying Facilities
376 SCHWENDIMAN, DI 9
Idaho Power Company
.
.
.
1 ("QF" under PURPA contract) expense. These adj ustments
2 were provided by Mr. Said. An adjustment of $579,982 was
3 made to reflect the 2008 kWh tax based on normalized
4 power supply. This adj ustment was provided by the
5 Company's tax department.
6 Q.Please describe the other adj ustments to the
7 statement of income on page two, columns 5 and 14, of
8 Exhibit No. 36.
9 A.Three other adj ustments were made, as shown on
10 page two, columns 5 and 14, of Exhibit No. 36. Those
11 are:(1) an adjustment of $1,075,535 to remove
12 non-recurring 2007 refund revenues, (2) an adjustment to
13 2007 expenses of negative $10,799,815, which is
14 $2,688,275 (revenues from Account 415) plus negative
15 $13,487,460 (removal of energy efficiency rider
16 revenues), and (3) an adjustment to 2008 revenues in the
17 amount of negative $113,778, which reflects the
18 transmission contracts with updated Open Access
19 Transmission Tariff ("OATT") rates. These adj ustments
20 were provided by Ms. Smith.
21 Q.Were there any other adj ustments made to the
22 operating expenses of the Company?
23 A.Yes. There are several adj ustments included in
24 column 14 of Exhibit No. 36 that were provided by and are
25 discussed in detail in the testimony of Ms. Smith.
377 SCHWENDIMAN, 01 10
Idaho Power Company
.
.
.
1 Q.Please describe Exhibit No. 37.
2 A.Exhibi t No. 37 consists of two pages and
3 provides detail of the adj ustments, by FERC account, to
4 the Company's electric plant in service used in this
5 proceeding.
6 Q.Please describe Exhibit No. 38.
7 A.Exhibi t No. 38 consists of two pages and
8 provides detail of the accumulated provision for
9 depreciation and amortization reserve.
10 Q.Please describe Exhibit No. 39.
11 A.Exhibi t No. 39 consists of two pages and
12 provides detail of other additions to or deductions from
13 the Company's total combined rate base.
l4 Q. Please describe Exhibit No. 40.
15 A.Exhibit No. 40 is a summary, by FERC account,
16 of the Company's operating revenues for the test period
17 used in this proceeding.
18
19
Q.Please describe Exhibit No. 41.
A.Exhibit No. 41 consists of six pages detailing
20 unadj usted and adj usted test year operation and
21 maintenance expenses for the twelve months ending
22 December 31, 2008.
23
24
25
Q.Please describe Exhibit No. 42.
378 SCHWENDlMAN, DI 11
Idaho Power Company
.
.
.
1 A.Exhibi t No. 42 consists of two pages and
2 provides greater detailed information by FERC account of
3 depreciation and amortization expenses used in this
4 proceeding.
5 Q.Please describe Exhibit No. 43.
6 A.Exhibi t No. 43 provides detailed information
7 regarding taxes other than income taxes and revenue
8 credi ts and debits used in this proceeding.
9 Q.Please describe Exhibit No. 44.
10 A.Exhibi t No. 44 is a one-page exhibit covering
11 regulatory debits and credits.
12 Q.Please describe Exhibit No. 45.
13 A. Exhibit No. 45 includes a detailed summary of
14 the income tax related adj ustments that result in the
15 adj usted tax expenses. The Company's tax department
16 provided these adj ustments.
17 Q.Have you prepared an exhibit that sets forth
18 the Idaho jurisdictional revenue deficiency?
19 A.Yes. I have prepared Exhibit No. 46 titled
20 "Jurisdictional Revenue Requirement" consisting of 36
21 pages.
22
23
Q.Please describe Exhibit No. 46.
A.Exhibi t No. 46 is the complete JSS detailing
24 allocation of each component of rate base, operating
25
379 SCHWENDIMAN, 01 12
Idaho Power Company
.
.
.
1 revenues, and expenses by FERC account resulting in the
2 Idaho jurisdictional revenue deficiency. The JSS is
3 organized as follows:
4 Summary of Results
5 Table 1 - Electric Plant in Service;
6 Table 2 - Accumulated Provision for
7 Depreciation (and Amortization) ;
8 Table 3 - Additions & Deletions to Rate
9 Base;
10 Table 4 - Operating Revenues;
11 Table 5 - Operation & Maintenance
12 Expenses;
13 Table 6 - Depreciation & Amortization
14 Expense;
15 Table 7 - Taxes Other Than Income Taxes;
16 Table 8 - Regulatory Debits & Credits;
17 Table 9 - Income Taxes;
18 Table 10 - Calculation of Federal Income
19 Tax;
20 Table 11 - State Income Tax - Oregon;
21 Table 12 - State Income Tax - Idaho and
22 Other;
23 Table 13 - Development of Labor Related
24 Allocator;
25 Table 14 - Allocation Factors;
380 SCHWENDIMAN, 01 13
Idaho Power Company
.
.
.
1 Table 15 - Distribution Jurisdictional
2 Allocation; and
3 Table 16 - Allocation Factors-Ratios.
4 Q.Please discuss the methodology used to
5 jurisdictionally separate costs in the preparation of
6 this study.
7 A.A three-step process was used to separate costs
8 among jurisdictions. The three steps are classification,
9 functionalization, and allocation of costs.In all three
10 steps, recognition was given to the way in which costs
11 are incurred by relating these costs to utility
12 operations. The methodology used to separate costs by
13 jurisdiction and calculate the Idaho jurisdictional
14 revenue requirement in the present case is the same
15 methodology accepted by the Idaho Public Utilities
16 Commission in previous rate cases.
17 Q.Would you please briefly explain the meaning of
18 classification, functionalization, and allocation?~
19 A.Classification groups costs into three
20 categories: demand-related, energy-related, and
21 customer-related. In addition to classification, costs
22 are functionalized; that is, costs are identified with
23 utility operating functions such as generation,
24 transmission, and distribution . Individual plant items
25 are examined and,
381 SCHWENDIMAN, DI 14
Idaho Power Company
.
.
.
1 where possible, the associated investment costs are
2 assigned to one or more operating functions. Once the
3 Company's total system costs are classified and assigned
4 to the appropriate function, they may be allocated among
5 jurisdictions.
6 The process of allocation is one of
7 apportioning the total system cost among jurisdictions by
8 introducing allocation factors into the process. An
9 allocation factor is an array of numbers which specifies
10 the jurisdictional value as a share or percent of the
11 total system quantity. For example, in the case of
12 energy-related costs, the allocation factor is annual
13 jurisdictional energy use, adjusted for losses, divided
14 by the total system energy use.
15 Once individual accounts have been allocated to
16 the various jurisdictions, it is possible to summarize
17 these into total utility rate base and net income by
18 jurisdiction. The results are stated in a summary form
19 to measure adequacy of revenues for the jurisdiction
20 under consideration. The measure of adequacy is
21 typically the rate of return earned on rate base, which
22 is compared to the requested rate of return.
23 Q.How have the various functional plant and cost
24 items been allocated?
25
382 SCHWENDIMAN, DI 15
Idaho Power Company
.
.
1 A.The average of the twelve monthly coincident
2 peak demands was used to allocate the demand-related
3 costs. This allocation method has been used by the
4 Company for the past two decades in all of its filings
5 requiring a jurisdictional separation study. This
6 allocation method was adopted by this Commission and
7 accepted by the Oregon Public Utility Commission and by
8 the Federal Energy Regulatory Commission. The
9 demand-related allocation factors used in the study are
10 designated as DI0, Dll, and 060. The respective values
11 used in these demand allocation factors are shown at line
12 numbers 976 through 979 of Exhibit No. 46.
13 Q. What method was used to allocate general plant
14 and certain labor-related administrative and general
15 expenses?
16 A.In accordance with FERC approved procedures,
17 general plant and administrative and general expenses
18 were allocated in accordance with functionalized wages
19 and salaries. These labor-related allocation factors are
20 shown on lines 777 through 972 of Exhibit No. 46.
21 Q.How were the energy-related expenses allocated
22 among jurisdictions?
23 A.Energy-related expenses were allocated based on
24 normalized jurisdictional kilowatthour sales and.25
383 SCHWENDIMAN, DI 16
Idaho Power Company
.
.
.
1 adjusted for losses to establish energy requirements at
2 the generation level. The energy-related allocation
3 factors used in the study are designated as EI0 and E99.
4 The respective values used in these energy allocation
5 factors are shown on lines 981 and 983 of Exhibit No. 46.
6 Q.What was the method by which you allocated
7 customer-related costs?
8 A.The principal customer-related expenses, which
9 required allocation, were meter reading (FERC Account
10 902), customer accounting, and billing (FERC Account
11 903). These accounts were allocated based upon a review
12 of actual Company practice of reading meters and
13 preparing monthly bills or statements.
14 Q. Please describe the derivation of the 2008
15 total system allocation factors used in this case.
16 A.The allocation factors in the 2008
17 Jurisdictional Separation Study were based on either the
18 2007 year-end data or 2008 assumptions. The capacity or
19 demand-related allocation factors (DI0, 011, and D60)
20 were created using the 5-year median demand ratios from
21 the load research sample applied to the 2008 test year
22 energy. The energy-related allocation factors were the
23 2008 test year load at generation level (EI0) and at
24 customer level (E99).
25
384 SCHWENDIMAN, DI 1 7
Idaho Power Company
.
.
.
1 Q.Briefly describe the manner in which you
2 allocated electric plant in service as shown in Table 1
3 of Exhibit No. 46.
4 A.Production plant was allocated to all
5 jurisdictions based on the average of the twelve monthly
6 coincident peaks. The allocation of transmission and
7 distribution plant was based on the same methodology.
8 Q.Would you describe the functional categories
9 used for allocation and direct assignment of transmission
10 plant and distribution substations?
11 A.Transmission facilities are the facilities that
12 form the bulk of the power transmission system together
13 wi th transmission, step-up substation facilities required
14 to introduce the Company's generation into the power
15 supply system and include facilities rated at 500 kV
16 through 46 kV. Distribution facilities refer to lower
17 vol tage lines and the substation facilities that provide
18 localized service. Some transmission and distribution
19 facilities were directly assigned to the customers who
20 paid for the exclusive use of those facilities.
21 Q.How have you allocated the accumulated
22 provision for depreciation and amortization of other
23 utility plant?
24
25
385 SCHWENDIMAN, DI 18
Idaho Power Company
.
.
.
1 A.Accumulated provision for depreciation was
2 allocated among jurisdictions as shown on Table 2 of
3 Exhibi t No. 46. The accumulated totals for each type of
4 production plant and for each primary plant account in
5 other functional groups were allocated based on the
6 related plant account as allocated in Table 1.
7 Amortization of other utility plant was functionalized
8 and then allocated based on the related plant items as
9 allocated in Table 1.
10 Q.Please describe Table 3 of Exhibit No. 46.
11 A.Table 3 details the allocation of all other
12 addi tions to or deductions from rate base. Deductions
l3 from rate base include customer advances for construction
14 that were directly assigned to the customers by
15 jurisdiction, and the accumulated deferred income taxes
16 that were allocated by plant. Additions to rate base
17 include:(1) materials and supplies which were
18 functionalized and allocated by the respective plant
19 allocators, (2) fuel inventory that was allocated on the
20 basis of energy, (3) components of IERCO, the Company's
21 fuel subsidiary, which were allocated based on energy,
22 and (4) deferred investment in Idaho conservation
23 programs which was directly assigned to the Idaho
24 jurisdiction.
25 All rate base items, with the exception of
accumulated deferred income taxes and the investment in
386 SCHWENDIMAN, DI 19
Idaho Power Company
.
.
.
1 conservation programs, reflect the average of ending
2 balances.
3 Q. Please describe Table 4 of Exhibit No. 46.
4 A. Table 4 contains the adjusted firm operating
5 revenues for each jurisdiction for the test year (twelve
6 months ending December 31, 2008). Opportunity sales are
7 non-firm energy sales to other utili ties, which were
8 credi ted to each jurisdiction in proportion to
9 generation-level energy use.
10 Other operating revenues were either allocated
11 among jurisdictions in a manner that offset related
12 allocations of rate base or, where a particular revenue
13 item could be associated with a specific jurisdiction,
14 directly assigned.
15 Q.Briefly describe the methods by which operation
16 and maintenance expenses were allocated.
17 A.The allocation of each operation and
18 maintenance expense is detailed on Table 5 of Exhibit No.
19 46. In general, the basis for each allocation is
20 identifiable with the source code listed on Exhibit No.
21 46. Demands are identified by a source code beginning
22 with a "D" prefix, energy use is identified by a source
23 code beginning with an "E" prefix, related plant is
24 identified by a line number source code, and
25 customer-weighted allocation factors begin with a "CW"prefix.
387 SCHWENDIMAN, DI 20
Idaho Power Company
.
.
.
1 Q.In what manner are supervision and engineering
2 expenses treated throughout the allocation of operation
3 and maintenance expenses?
4 A.For the applicable expense account in each
5 functional group, the labor component was separately
6 allocated in accordance with the detail provided on Table
7 13 of Exhibit No. 46. The total of allocated labor in
8 each functional group became the basis for the allocation
9 of supervision and engineering expense. Total allocated
10 labor expense served the additional purpose of allocating
11 employee pension and other labor-related taxes and
12 expenses. Table 13 of Exhibit No. 46 details the
13 development of all the labor-related allocation factors
14 used in this study.
15 Q.Please describe Table 6 of Exhibit No. 46.
16 A.The allocation of depreciation expense and
17 amortization of limited term plant is set forth on Table
18 6. These expenses were identified by type of production
19 plant or by primary plant account for other functional
20 plant groups and allocated consistent with the related
21 plant account.
22 Q.Please describe Table 7 of Exhibit No. 46 and
23 the allocation of taxes other than income taxes.
24
25
388 SCHWENDIMAN, DI 21
Idaho Power Company
.
.
.
1 A.Taxes other than income taxes were treated
2 indi vidually and allocated in a manner consistent with
3 the bases by which the respective taxes are assessed.
4 Q.Please describe Table 8 of Exhibit No. 46.
5 A.Table 8 of Exhibit No. 46 lists the regulatory
6 debi ts and credits for amortization of professional fees.
7 No amounts were included in the 2008 test year.
8 Q.Please describe Table 9 of Exhibit No. 46.
9 A.The expenses shown on Table 9 consist of
10 deferred income taxes and the investment tax credit
11 adjustment and were functionalized and allocated based on
12 total allocated plant. State and Federal income tax
13 liabilities are also summarized on Table 9. The income
14 taxes shown on Tables 10 through 12 were obtained from
15 the Company's tax department.
16 Q.Please describe how you allocated federal and
17 state income taxes shown on Tables 10 through 12 of
18 Exhibit No. 46.
19 A.The respective tax bases were developed, and
20 taxes were calculated directly for each jurisdiction.
21 Operating income before taxes represents adjusted
22 operating revenues less all adj usted operating expenses
23 treated heretofore with the exception of deferred income
24 taxes and
25
389 SCHWENDIMAN, DI 22
Idaho Power Company
.
.
.
1 investment tax credits. Adj usted long-term and other
2 interest expenses were allocated by total plant to
3 develop net operating income before taxes. From that
4 point forward, additions to or deductions from the
5 respecti ve tax bases were allocated to each jurisdiction
6 by net income before taxes. In this manner, taxable
7 income for each jurisdiction was developed and the
8 appropriate tax rate was applied. Final tax amounts
9 resul t after the allocation of adj ustments and tax
LO credi ts. All details relating to the calculation of
11 Federal, Oregon, Idaho, and other state income taxes are
12 found on Tables 10, 11, and 12.
13 Q.Please describe Tables 13 through 16 of Exhibit
14 No. 46.
15 A.Tables 13 through 16 of Exhibit No. 46 list the
16 principal allocation factors used in the study and the
17 respecti ve jurisdictional values for each allocation
18 factor. Table 16 lists the ratios of the principal
19 allocation factors included in Table 14.
20 Q.Please describe the development of the Idaho
21 Jurisdictional revenue deficiency.
22 A.The summary of results is presented on pages
23 one and two of Exhibit No. 46. The development of the
24 Idaho jurisdictional revenue deficiency is presented in
25 the column entitled "Idaho Retail" on page one of Exhibit
No.
390 SCHWENDIMAN, 01 23
Idaho Power Company
.
.
.
1 46. The Idaho net income of $145,689,752 (line 26)
2 resul ted in a return on rate base of 6.96 percent (line
3 27). Based upon the Company's request for an overall
4 rate of return of 8.55 percent provided by Mr. Steven
5 Keen, the Company's Idaho jurisdictional net income
6 should be $178, 985, 602, as shown on line 32. The
7 resulting earnings deficiency is $33,295,851, as shown on
8 line 33.
9 Q.Have any changes been made to the summary of
lO results for this case?
11 A.Yes, I have adj usted the earnings deficiency
12 upward by $7,636,142 to reflect the Construction Work in
13 Progress ("CWIP") recovery proposal as sponsored by Ms.
14 Miller in this case. The resulting net earnings
15 deficiency with the CWIP addition is $ 4 0,553,158 for the
16 Idaho Jurisdiction.
17 Q.What net-to-gross or incremental income tax
18 factor did you use in developing the Idaho jurisdictional
19 revenue deficiency?
20 A.The composite incremental tax multiplier of
21 1.642 is the assimilation of the Federal effective tax
22 rate, an Idaho composite tax rate, an Oregon composite
23 tax rate, and an additional state composite tax rate.
24 This value, as shown on line 37 of Exhibit No. 46, was
25 provided by the Company's tax department.
391 SCHWENDIMAN, 01 24
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 Q.What is the resulting Idaho jurisdictional
2 revenue deficiency?
3 A.The result of the Jurisdictional Separation
4 Study, as shown on page one, line 38 of Exhibit No. 46,
5 indicates a total revenue deficiency of $66,588,286 for
6 the Idaho retail jurisdiction. This represents a
7 required 9.89 percent increase in normalized Idaho
8 jurisdictional revenues.
9 Q.Does this conclude your testimony?
A.Yes, it does.
392 SCHWENDIMAN, DI 25
Idaho Power Company
.
.
.
1
2 open hearing.)
(The following proceedings were had in
4 cross-examination.
MR. WALKER: The witness is available for3
5 COMMISSIONER SMITH: Thank you. Let's
6 see, Mr. Bruder, do you have any questions for this
7 witness?
8
9
10
11 you.
12
13
14
15
16
MR. BRUDER: No questions.
COMMISSIONER SMITH: Mr. Miller.
Mr. Miller: No, no questions. Thank
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Just one, Madam Chair.
CROSS-EXAMINATION
17 BY MR. RICHARDSON:
18 Q Can you just give us a general feel for
19 how the relationship in terms of size in terms of
20 customers and load, how that relationship is changing
21 over the near term between the Idaho and Oregon
22 jurisdictions?
23 A
24 insignificant.
25
I think if there are any changes, they are
MR. RICHARDSON: That's all I have.
CSB REPORTING
[phone]
393 SCHWENDIMAN (X)
Idaho Power Company
.
.
.
1
2 Mr. Purdy.
COMMISSIONER SMITH: Thank you.
MR. PURDY: No questions.
COMMISSIONER SMITH: Mr. Olsen.
MR. OLSEN: No questions.
COMMISSIONER SMITH: Mr. Ward.
MR. WARD: No questions. Thank you.
COMMISSIONER SMITH: Mr. Price.
MR. PRICE: No questions.
COMMISSIONER SMITH: Wow. Any from the
COMMISSIONER REDFORD:No questions.
3
4
5
6
7
8
9
10
11 Commission?
12
13
14
COMMISSIONER SMITH: Nor I. Any redirect?
MR. WALKER: No redirect, and may I ask
15 that if there's nothing further that Ms. Schwendiman as
16 well as Ms. Miller be excused?
17 COMMISSIONER SMITH: If there's no
18 obj ection, Ms. Miller and Ms. Schwendiman will be
19 excused.
20 (The witness left the stand.)
21
22 Greg Said.
23
24
25
MR. KLINE: Idaho Power's next witness is
CSB REPORTING
[phone]
394 SCHWENDIMAN (X)
Idaho Power Company
.
.
.
1
2
GREGORY W. SAID,
produced as a witness at the instance of the Idaho Power
3 Company, having been first duly sworn, was examined and
4 testified as follows:
5
6
7
8 BY MR. KLINE:
9 Q
DIRECT EXAMINATION
Would you please state your name for the
Gregory W. Said.
And by whom and in what capacity are you
13 employed, Mr. Said?
16 Q
10 record?
11 A
14 A I'm employed by Idaho Power as the
18 52?
A
20 through 52.
12 Q
15 director of state regulation.
And on June 27th of this year did you file
17 28 pages of direct testimony and Exhibits 50 through
19
21 Q
The testimony, yes. The exhibits are 47
Oh, okay, and on December 3rd did you
22 prefile rebuttal testimony?
23
24
25
A
Q
right?
Yes.
And it was 14 pages in length; is that
CSB REPORTING
[phone]
395 SAID (Di)
Idaho Power Company
.
.
.
1 A That's correct.
2 Q And which exhibit did you file with your
3 testimony?
4 A 87.
5 Q Thank you. Mr. Said, do you have any
6 addi tions or corrections that you need to make to
7 ei ther your direct or rebuttal testimony that you
8 prefiled?
9 A A couple of updates and one correction.
10 The first update has already been addressed in your
11 question as to my position with Idaho Power. On page 1,
l2 line 7 of my prefiled testimony, I stated that I was the
13 manager of revenue requirement and that designation has
l4 changed. The second update is on page 20 at line 14. I
15 was asked the question, "Do you have a recommendation for
16 the appropriate level of the LGAR beginning in April
17 2009?" My response was, "No. Per Order No. 30508, the
18 Commission has directed the Commission Staff, the Company
19 and interested parties to convene workshops to seek
20 agreement as to the appropriate LGAR methodology to be
21 used after March 2009."
22 My update at this time is that those
23 workshops were held, agreement was reached and a
24 stipulation was presented to the Commission in Case
25 No. IPC-E-08-19 and I recommend that the Commission
CSB REPORTING
[phone]
396 SAID (Di)
Idaho Power Company
.
.
.
1 approve the LGAR methodology as presented in the
2 stipulation of the parties in that case. The one
3 correction that I have is on page 26 of my direct
4 testimony. On line 15, I refer to page 2 of Exhibit
5 No. 52. In reality, that's a one-page exhibit, so it
6 should now read, "Page 1 of Exhibit No. 52 shows the
7 planned use of those additional facilities...," and there
8 are no changes to my rebuttal testimony.
9 Q Wi th those updates and changes to your
10 direct testimony, if I were to ask you the same
11 questions that are set out in your prefiled direct and
12 rebuttal testimony, would your answers be any different
13 today?
14 A No, they'd be the same.
15 MR. KLINE: With that, Madam Chairman, I'd
16 request that Mr. Said's direct testimony and rebuttal
17 testimony be spread on the record as if presented today
18 and that his exhibits, both direct and rebuttal, be
19 marked for identification.
20 COMMISSIONER SMITH: If there's no
21 obj ection, we will spread the prefiled testimony of
22 Mr. Said upon the record as if read and identify Exhibits
23 47 through 52 and 87.
24
25
MR. KLINE: Thank you.
CSB REPORTING
[phone]
397 SAID (Di)
Idaho Power Company
1 (The following prefiled direct and.2 rebuttal testimony of Mr.Gregory w.Said is spread upon
3 the record.)
4
5
6
7
8
9
10
11
12
13.14
l5
16
17
18
19
20
21
22
23
24.25
CSB REPORTING 398 SAID (Di)(208 )890-5198 Idaho Power Company
.
.
.
1 Q.Please state your name and business address.
2 A.My name is Gregory W. Said and my business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what capacity?
5 A.I am employed by Idaho Power Company as the
6 Manager of Revenue Requirement in the Pricing and
7 Regulatory Services Department.
8 Q.Please describe your educational background.
9 A.In May of 1975, I received a Bachelor of
10 Science degree in Mathematics with honors from Boise
11 State University. In 1999, I attended the Public Utility
l2 Executi ves Course at the Uni versi ty of Idaho.
13
14
15
Q. Please describe your work experience with Idaho
Power Company.
A.I became employed by Idaho Power Company in
16 1980 as an analyst in the Resource Planning Department.
17 In 1985, the Company applied for a general revenue
18 requirement increase. I was the Company witness
19 addressing power supply expenses.
20 In August of 1989, after nine years in the
21 Resource Planning Department, I was offered and I
22 accepted a position in the Company's Rate Department.
23 With the Company's application for a temporary rate
24 increase in
25
399 SAID, 01 1
Idaho Power Company
.
.
..
1 1992, my responsibilities as a witness were expanded.
2 While I continued to be the Company witness concerning
3 power supply expenses, I also sponsored the Company's
4 rate computations and proposed tariff schedules in that
5 case.
6 Because of my combined Resource Planning and
7 Rate Department experience, I was asked to design a Power
8 Cost Adj ustment (" PCA") which would impact customers'
9 rates based upon changes in the Company's net power
10 supply expenses. I presented my recommendations to the
11 Idaho Public Utilities Commission in 1992, at which time
12 the Commission established the PCA as an annual
13 i
adjustment to the Company's rates. I sponsored the
14 Company's annual PCA adjustment in each of the years 1996
15 through 2003. I continue to supervise PCA-related
16 regulatory filings.
17 In 1996, I was promoted to Director of Revenue
18 Requirement and in 2002 I was promoted to Manager of
19 Revenue Requirement. I have managed the preparation of
20 revenue requirement information for regulatory
21 proceedings since 1996.
22 Q.What topics will you discuss in your testimony
23 in this proceeding?
24 A.My testimony can be divided into four sections
25 addressing (1) power supply expense modeling, (2) PCA
changes resulting from base rate changes, (3) revenue
400 SAID, DI 2
Idaho Power Company
.
.
.
15
1 requirement adj ustments that I provided to Ms.
2 Schwendiman, and (4) revenue requirement observations and
3 conclusions.
4 POWER SUPPLY EXPENSE MODELING
5 Q.What role does power supply expense modeling
6 play in a general rate case?
7 A.Power supply expense modeling in a general rate
8 case provides the Commission with a view of "normal"
9 expectations for fuel expense (FERC accounts 501 and
10 547), purchased power expense (FERC account 555), and
11 surplus sales revenue (FERC account 447). Power supply
12 investment, depreciation expense, and operating and
13 maintenance expenses are reflected in other FERC accounts
14 that are not addressed by power supply expense modeling.
Q.Please define the term "variable power supply
16 expenses" as the Company and the Commission have used the
17 term historically.
18 A.The Company and the Commission have
19 traditionally used the term "variable power supply
20 expenses" to refer to the sum of fuel expenses (FERC
21 accounts 501 and 547) and purchased power expenses (FERC
22 account 555) excluding expenses due to purchases from
23 PURPA qualifying facilities ("PURPA") minus surplus sales
24 revenues (FERC account 447). Because surplus sales
25 revenues are subtracted from fuel and purchased power
401 SAID, DI 3
Idaho Power Company
.
.
.25
1 supply expenses, variable power supply expenses are also
2 referred to as net power supply expenses. For ratemaking
3 purposes, PURPA expenses have been quantified separately
4 from variable power supply expenses and are treated as
5 fixed inputs to power supply modeling rather than
6 variable outputs.
7 Q.How are variable power supply expenses
8 "normalized" for ratemaking purposes?
9 A.Variable power supply expenses are determined
10 for each water condition dating back to 1928. In this
11 case, 80 water conditions have been evaluated. The
12 average of th~ variable power supply expenses over the
13 range of hydro conditions is considered "normal" or
14 representative of the possible circumstances the Company
15 might encounter for ratemaking purposes. The Idaho
16 Public Utili ties Commission first adopted this method of
17 averaging a representative range of power supply expenses
18 associated with multiple water conditions to determine
19 normalized power supply expenses in 1981.
20 Q.Have you supervised the preparation of
21 normalized variable power supply expense modeling to
22 reflect the current test year 2008 characteristics?
23 A.Yes. Under my supervision and at my request, a
24 power supply simulation that is representative
402 SAID, 01 4
Idaho Power Company
.
.
21
1 of the test year 2008 variable power supply expenses
2 associated with 80 separate water conditions was
3 prepared. This year the analysis includes water
4 conditions corresponding to years 1928 through 2007. The
5 average of the variable power supply expenses related to
6 each of the 80 water conditions represents the
7 normalization of variable power supply expenses.
8 Q.Please describe the simulation of test year
9 2008 variable power supply expenses.
10 A.The simulation of test year 2008 variable power
II supply expenses reflects 2008 normalized loads and
12 resources that include 127 average megawatts of PURPA
13 generation. The 2008 PURPA generation amount includes a
14 reduction of 62 average megawatts from the PURPA
15 generation amount used in 2007. This reduction is due to
16 a number of PURPA proj ects changing their contracts to
17 delay their on-line dates beyond December 2008.
l8 Q.Have you supervised the preparation of an
19 exhibit to de~onstrate the normalization of variable
20 power supply expenses for the test year 2008?
A.Yes . Exhibit No. 47 shows the results of the
22 variable power supply expense normalization modeling for
23 the test year 2008.
24.25
403 SAID, DI 5
Idaho Power Company
.
.
1 Page 1 of Exhibit No. 47 shows the summary
2 resul ts containing the 80-year average variable power
3 supply generation sources and expenses. Pages 2 through
4 81 contain results for each of the 8 0 individual water
5 conditions 1928 through 2007.
6 Q.How has the annual PURPA expense changed since
7 the last general rate case that used a 2007 test year?
8 A.The annual PURPA expense for test year 2008 has
9 decreased from $93.1 million to $63.3 million reflecting
10 the delay of 62 average megawatts of anticipated PURPA
11 proj ects that I mentioned earlier in my testimony.
12 Q.Have you supervised the preparation of an
13 exhibi t detailing the test year 2008 PURPA proj ect
14 generation and expenses?
15 A.Yes. I supervised the preparation of Exhibit
16 No. 48 which consists of one page. Column 1 of Exhibit
17 No. 48 shows the generation and expenses associated with
18 contracted PURPA proj ects that will be on-line during the
19 test year 2008.
20 Q.What are the corresponding variable power
21 supply expenses for the 2008 test year based upon this
22 level of PURPA generation and expense?
23
24.25
404 SAID, DI 6
Idaho Power Company
.
.
.
14
15
1 A.The normalized variable power supply expense
2 for the 2008 test year as shown on Page 1 of Exhibit No.
3 47 is $88.4 million. This amount is $47.5 million
4 greater than the Company's filed 2007 test year
5 normalized variable power supply expenses and $53.5
6 million greater than the 2007 test year normalized
7 variable power supply expenses as determined in Order No.
8 30508 based upon a stipulation of the parties in Case No.
9 IPC-E-07-08.
10 Q.What do the $29.8 million decrease in PURPA
11 expense and the $53.5 million increase in normalized
12 variable power supply expense indicate with respect to
13 the change in net total power supply expense from test
year 2007 to test year 2008?
A.It indicates a $23. 7 million net total power
16 supply expense increase ($53.5 million additional expense
17 - $29.8 million reduction in expense = $23.7 million net
18 increase) to serve increased test year 2008 loads with
19 reduced PURPA. generation sources. Base on those amounts,
20 I instructed Ms. Schwendiman to use the $88.4 million of
21 net variable power supply expense as shown on page 1 of
22 Exhibi t No. 47 and the corresponding PURPA expense of
23 $ 63.3 million as shown on page 1 of Exhibit No. 48 in her
24 quantification of the Company's 2008 revenue requirement.
25 This represents a total PURPA and variable power supply
expense of $151.7
405 SAID, DI 7
Idaho Power Company
.
.
.
l4
1 million ($88.4 million + $ 63.3 million = $151. 7 million),
2 which is an increase of $23.7 million from the 2007 test
3 year determination of $128.0 million.
4 Q.Has there been any change in the Company's
5 system load since the last general rate case,
6 IPC-E-07-08?
7 A.Yes. The Company's 2007 annual normalized
8 system load used in the IPC-E-07-08 general rate case was
9 15.6 million megawatt-hours ("MWh"). The Company's 2008
10 annual normalized system load used in this case is 15.9
11 million MWh, an approximate 1.9 percent (15.9 million MWh
12 / 15.6 million MWh = 1.92 percent) increase in system
13 load.
Q.Please recap the change in total PURPA and
15 variable power supply expenses that corresponds to the
16 1.9 percent higher loads of 2008 and the reduction in
17 contracted PURPA resources.
18 A.The Company's determination of normalized
19 variable power supply expenses for the test year 2008 in
20 this case is $ 8 8.4 million (page 1 of Exhibit No. 47).
21 The corresponding 2008 PURPA expense is $63.3 million
22 (page 1 of Exhibit No. 48) for a total 2008 PURPA and
23 variable power supply expense of $151.7 million ($88.4
24 million + $ 63.3 million = $151. 7 million). The
25 Commission adopted a 2007 normalized variable power
406 SAID, DI 8
Idaho Power Company
.
12.13
14
15
16
17
18
19
20
21
22
23
24.25
1 supply expense for the test year 2007 of $34.9 million.
2 The corresponding test year
3
4 /
5
6 /
7
8 /
9
10
11
407 SAID, DI 8a
Idaho Power Company
.
.
.
1 2007 PURPA expense was $93.1 million for a total 2007
2 PURPA and variable power supply expense of $128.0 million
3 ($34.9 million + $93.1 million = $128.0 million). Total
4 normalized PURPA and variable power supply expenses have
5 grown by $23.7 million ($151.7 million - $128.0 million =
6 $23. 7 million).
7 Q.Have the modeled market prices of energy
8 changed in the last year?
9 A.Yes. Modeled market prices for energy sold as
10 surplus are slightly lower than market prices last year.
11 In the IPC-E-07-08 case, monthly-modeled surplus sales
12 prices fluctuated from $21 per MWh to $118 per MWh
l3 depending on market conditions. The annual fluctuation
14 of modeled surplus sales prices in that case was from $34
15 per MWh to $ 7 3 per MWh. In this case, monthly-modeled
16 surplus sales prices fluctuate from $16 per MWh to $104
17 per MWh. The annual fluctuation of modeled surplus sales
18 prices in this case is from $30 per MWh to $79 per MWh.
19 Because of the additional load and reduction of PURPA
20 generation, surpluses have been reduced during the
21 highest market price periods of time bringing the
22 averaged weighted price for surplus sales down. With the
23 load growth that the Company has experienced and the
24 reduction of PURPA generation, the normalized volume of
25 surplus sales has decreased from 3.0
408 SAID, DI 9
Idaho Power Company
.
.
1 million MWh to 2.4 million MWh.
2 Modeled market prices for energy purchased are
3 also slightly lower than market prices last year. In the
4 IPC-E-07-08 case, monthly-modeled purchased power prices
5 fluctuated from $15 per MWh to $165 per MWh depending on
6 market conditions. Annual fluctuation of modeled
7 purchased power prices in that case was from $42 per MWh
8 to $116 per MWh. In this case, monthly-modeled purchased
9 power prices fluctuate from $13 per MWh to $ 93 per MWh.
10 The annual fluctuation of modeled purchased power prices
11 in this case is from $22 per MWh to $81 per MWh. While
12 there has been a slight decrease in the modeled purchased
13 power prices, the normalized volume of purchased power
14 has increased from 401 thousand MWh to 472 thousand MWh
15 due to seasonal load growth.
16 Q.Have fuel prices for Company-owned coal-fired
17 generating plants changed over the last two years?
18 A.Yes. The cost of coal at the Bridger plant has
19 increased from $14.51 per megawatt-hour to $16.12 per
20 megawatt-hour. The cost of coal at the Boardman plant
21 has increased from $13.91 per megawatt-hour to $14.36 per
22 megawatt-hour. The cost of coal at the Valmy plant has
23 increased from $22.06 per megawatt-hour to $24.12 per
24 megawatt-hour. Coal price increases are the result of a.25
409 SAID, DI 10
Idaho Power Company
.
.
.
1 number of factors, principally, the costs of mining and
2 transportation. Higher costs for steel, explosives,
3 tires, and diesel fuel as well as higher costs to remove
4 overburden associated with deeper coal seams have
5 combined to drive coal mining costs higher. Once mined,
6 coal is transported via railroad cars, again at higher
7 costs than in 2007. Higher mining costs and higher
8 transportation costs result in higher ultimate fuel
9 costs. The fuel cost for the Boardman coal-fired plant
10 has not increased at the same pace as the fuel costs at
11 the Bridger and Valmy plants based upon a below-market
12 price contract that will expire at the end of 2008.
13 Q. Have modeled variable gas prices for
14 Company-owned plants changed over the last two years?
15 A.Yes. For test year 2007, the Company modeled
16 gas prices at $ 98.32 per megawatt-hour for the two
17 smaller Danskin units and $86.45 per megawatt-hour for
18 the Bennett Mountain unit. Modeled variable gas prices
19 for the 2008 test year are $79.90 per megawatt-hour for
20 the three Danskin units and $81.96 per megawatt-hour at
21 Bennett Mountain. The reduction in variable gas prices
22 for the three Danskin units reflects the addition of
23 Danskin unit 1 that has a lower heat rate than the older
24 Danskin units. The reduction in the Bennett Mountain
25 variable gas rate is
410 SAID, 01 11
Idaho Power Company
.
.
.
1 reflecti ve of a slight reduction after the post-hurricane
2 spikes in gas prices.
3 Q.In light of load growth, PURPA resource
4 decline, market price changes, and fuel cost changes, do
5 you believe the Company's modeled power supply expenses
6 represent a reasonable estimate of normalized power
7 supply expenses for the test year 2008?
8 A.Yes, I do.
9 Q.Please summarize the Company's sources of
10 energy as shown on page 1 of Exhibit No. 47.
11 A.From the summary information contained on page
12 1 of Exhibit No. 47, it can be seen that for the test
13
14
year 2008, Company-owned hydro generation supplies 8.7
million MWh while Company-owned thermal generation
15 supplies 7.4 million MWh (Bridger 5.1, Boardman 0.4, and
16 Valmy 1.9). This is essentially the same generation
17 output from Company-owned resources that was envisioned
18 in the 2007 test year. Danskin and Bennett Mountain, as
19 peaking plants, operate intermittently, but offer
20 significant contribution at important times when
21 resources and purchases are inadequate to serve peak
22 loads.
23 Purchases of power come from three sources:
24 market purchases, contract purchases other than PURPA,
25 and PURPA purchases. PURPA purchases are assumed at
fixed normalized
411 SAID, 01 12
Idaho Power Company
.
.
.
1 levels amounting to nearly 1.1 million MWh. Because the
2 PURPA purchases are fixed inputs to power supply
3 modeling, they are not shown on the variable output
4 summary, however, when combined with the market and other
5 contract purchases of 1.0 million MWh, total purchases
6 amount to 2.1 million MWh (1.1 million MWh + 1.0 million
7 MWh).
8 Total hydro and coal-fired generation amounts
9 and purchases add up to 18.2 million MWH (8.7 + 7.4 + 2.1
10 = 18.2). Hydro generation contributes approximately 48
11 percent (8. 7 million MWh / 18.2 million MWh = 48 percent)
12 of the generation mix, thermal generation contributes
13 approximately 41 percent (7.4 million MWh / 18.2 million
14 MWh = 41 percent), and purchases contribute approximately
15 11 percent (2.1 million MWh / 18.2 million MWh = 11
16 percent) .
17 Q.How. is the energy from the resources you just
18 described used?
19 A.Of the over 18.2 million MWh consumed, 15.9
20 million MWh are utilized for system loads while over 2.3
21 million MWh are sold as surplus. With load growth and
22 the reduction in PURPA generation, surplus sales have
23 been reduced from the 2.9 million MWh anticipated in the
24 2007 test year.
25
412 SAID, DI 13
Idaho Power Company
.
.
.
1 Q.Please summarize the expense and revenue
2 information associated with the normalized power supply
3 operations that you have just described.
4 A.Exhibi t No. 47 contains variable expense and
5 revenue information limited to FERC accounts 501, Fuel
6 (coal); 547, Fuel (gas); 555, Purchased Power; and 447,
7 Sales for Resale. Hydro generation has no assumed fuel
8 expense. Coal expenses of $133.4 million are comprised
9 of Bridger at $82.1 million, Valmy at $45.3 million and
10 Boardman at $ 6.0 million. Gas expenses amount to $ 7.1
II million. Purchased power expenses, not including PURPA,
12 amount to $58.1 million while surplus sales amount to
13 $110.2 million. Altogether, net variable power supply
14 expenses amount to $88.4 million ($133.4 million + $7.1
15 million + $58.1 million - $110.2 million = $88.4
16 million) .
1 7 PCA CHAGES
18 Q.How do base level PCA expenses differ from test
19 year variable power supply expenses?
20 A.Base level PCA expenses differ from test year
21 variable power supply expenses in two ways. First, base
22 level PCA expenses include PURPA expenses. Second, base
23 level PCA expenses are determined for an April through
24 March time frame rather than a calendar year. April
25 represents the beginning of the runoff period that
provides
413 SAID, 01 14
Idaho Power Company
.
.13
14
15
1 the basis for the PCA proj ection.
2 Q.What is the base level of PCA expenses for test
3 year 2008?
4 A.In this case, normalized power supply expenses
5 amount to $88.4 million and normalized PURPA expenses
6 amount to $63.3 million. The sum, $151.7 million,
7 represents the new base PCA expense level.
8 Q.Are you sponsoring an exhibit that shows the
9 derivation of the appropriate new PCA regression formula
10 to be used for projecting the next year's PCA expenses?
11 A.Yes. Exhibit No. 49 was prepared under my
12 supervision to show the derivation of the new PCA
regression formula.
Q. Please describe Exhibit No. 49.
A.Exhibi t No. 49 consists of six columns. Column
16 1 shows the number of the observation from 1 to 79.
17 Column 2 contains the PCA year corresponding to each
18 observation; observation 1 is 1928, observation 2 is
19 1929, and so on through observation 79 which is 2006.
20 Because the PCA year is for months April through March of
21 the following year, there are only 79 observations
22 instead of the 80 conditions represented in Exhibit No.
23 47. Column 3 contains the April through July runoff
24 measured at Brownlee Dam for each of the observation.25 years 1928 through 2006.
414 SAID, DI 15
Idaho Power Company
.
.
.
1 Column 4 contains the natural logarithm of the runoff
2 value contained in Column 3. Column 5 contains the April
3 through March annual power supply expense based upon data
4 from Exhibit No. 47, but reflecting PCA-year totals
5 rather than calendar year totals. Finally, Column 6
6 contains the regression predicted value of April through
7 March annual power supply expenses.
8 To the right of the columns is summary output
9 of certain regression statistics (such as r-square) and
10 formula coefficients.
11 Q.Please describe the new PCA regression formula
12 based upon Exhibit No. 49.
13 A. The basic PCA formula takes the following form:
14 Annual PCA expense = Cl - C2 * ln (Brownlee runoff) + C3.
15 The values of Cl, C2 and C3 are constant with the only
16 variable being April through July runoff measured at
17 Brownlee Dam. The equation without C3 is used to predict
18 net power supply expenses and is the direct result of the
19 regression analysis contained in Exhibit No. 49. The
20 constant Cl represents the prediction of annual net power
21 supply expense that would occur if there was zero April
22 through July runoff at Brownlee. The value of Cl is
23 $2,595,771,216. In reality, the lowest April through
24 July runoff measured at Brownlee contained in the
25 observations
415 SAID, DI 16
Idaho Power Company
.1 is 1.93 million acre-feet which occurred in the 1992
2 observation.
3 Because the regression provides a linear fit of
4 a non-linear transformation, the value of C2 is somewhat
5 difficult to explain. Observed Brownlee runoff data in
6 acre-feet is first transformed by the natural logarithm
7 function. For each unit increase in the natural
8 logari thm of the Brownlee runoff data the proj ection of
9 annual power supply expenses will be reduced by C2, which
10 is $162,707,198. The average natural logarithm of
11 Brownlee runoff values, based upon the observations
12 contained in Exhibit No. 49, is 15.41. This value.13 corresponds to a runoff of approximately 4.9 million
14 acre-feet (e A 15.41 = 4,925,814 million acre-feet).
15 With a runoff of 4.9 million acre-feet and a natural
16 logarithm of 15.41, the projected net power supply
17 expenses would be $88,453,295 ($2,595,771,216 -
18 ($162,707,198 * 15.41)). An increase of 1 to the natural
19 logari thm would result if the runoff was approximately
20 13.4 million acre-feet (In (13, 389, 749) equals 16.41
21 which equals 15.41 + 1.0). With a runoff of 13,389,749
22 acre-feet, the net power supply expenses would be
23 $162,707,198 less than $88,453,295 making the projection
24 of power supply expenses a negative $74,253,903.25 ($2,595,771,216 - ($162,707,198 * 16.41) = -$74,253,903).
416 SAID, DI 17
Idaho Power Company
.
.
.24
25
1 The natural logarithms of observed Brownlee
2 runoff ranged from 14.47 (1992 runoff) to 16.25 (1984
3 runoff). The difference, 1.78 (16.25 - 14.47),
4 multiplied by $162,707,198, equals approximately $290
5 million, which represents the change in proj ected power
6 supply expenses from the highest water case (1984) to the
7 lowest water case (1992).
8 The value of C3 is $63,269,889, which is the
9 normalized PURPA expense. Because the normalized PURPA
10 expense is quantified separately from net variable power
11 supply expenses, it is added to net variable power supply
12 expenses to determine the PCA expenses.
13 Q. What is the new PCA regression equation with
14 values inserted for the constants?
15 A.The new PCA regression equation is:
16 Annual PCA expense = $2,595,771,216
17 - $162,707,198 * ln (Brownlee runoff)
18 + $63,269,889.
19 Q.How does the range in proj ected power supply
20 expenses from high condition to low condition resulting
21 from this regression equation compare to the
22 corresponding range of proj ected power supply expenses
23 based upon the previous regression equation?
417 SAID, DI 18
Idaho Power Company
1 A.The predictions of power supply expenses based.2 upon the regression observations contained in the
3 previous regression analysis ranged by $333 million from
4 the highest estimate to lowest estimate of power supply
5 expenses. The current range varies by only $290 million
6 as a result of slightly lower market price assumptions
7 which have reduced the volatility in power supply
8 expenses.
9 Q.Please describe what is meant by the term
10 "embedded" cost.
11 A.The term "embedded" cost refers to an average
12 cost that is "embedded" in the rates and charges paid by.13 the Company's customers. Included wi thin all customer
14 class rates is an embedded component related to the total
15 of PURPA and variable power supply expenses. There would
16 also be embedded components related to other generation
17 related expenses, transmission related expenses,
18 distribution related expenses, general and administrative
19 expenses, and returns. All customer classes have the
20 same embedded PURPA and variable power supply cost
21 because no customer class has preferential rights to
22 energy. As a result, the embedded rate for PURPA and
23 power supply expenses as reflected as a component of the
24 overall rate is determined by dividing the test year.25 total PURPA and variable power supply expenses by the
total system load.
418 SAID, 01 19
Idaho Power Company
.
.
1 Q.What is the embedded total PURPA and variable
2 power supply expense rate at the generation level as
3 derived from data contained in Exhibit No. 47?
4 A.The embedded total PURPA and variable power
5 supply expense rate at generation level is $9.56 per
6 megawatt-hour ($151,691,135 / 15,863,628 megawatt-hours
7 $ 9.56 per megawatt-hour) .
8 Q.How does the embedded total PURPA and variable
9 power supply expense rate compare to the Commission
10 approved Load Growth Adjustment Rate ("LGAR")?
11 A.The Commission approved LGAR is $62.79 per MWh,
12 but is only applied to one-half of load growth in the
13 2008 PCA year making the rate effectively $31.40 per MWh.
14 Q. Do you have a recommendation for the
15 appropriate level for the LGAR beginning in April 2009?
16 A.No. Per Order No. 30508, the Commission has
17 directed the Commission Staff, the Company and interested
18 parties to convene workshops to seek agreement as to the
19 appropriate LGAR methodology to be used after March 2009.
20 Q.Did Commission Order No. 30215 direct the
21 Company to update marginal cost studies and line loss
22 data in general rate proceedings?
23
24.25
A.Yes.
419 SAID, DI 20
Idaho Power Company
.
.
.
1 Q. Please define "marginal" costs with relation to
2 PURPA and variable power supply costs.
3 A."Marginal" costs refer to a very specific
4 computational method of determining incremental costs for
5 a hypothetical situation where no model inputs change
6 other than load. Rather than measuring the change in
7 total PURPA and variable power supply expenses from one
8 year to the next and dividing by the change in load from
9 the first year to the next, marginal costs are determined
10 based upon a hypothetical instantaneous load change and
11 the resulting modeled expense change to serve that load
12 change. In recent analyses, marginal costs are also
13 based upon a five-year average.
14 Q. At your direction, did the Company prepare
15 marginal cost analyses in conj unction with this case?
16 A.Yes. Exhibit No. 50 contains a quantification
17 of the five-year average marginal energy cost at
18 generation level (i. e. including line losses) as $ 65.98
19 per megawatt-hour using standard marginal cost
20 methodology and 2008 through 2012 data. The annual
21 marginal cost for the single year 2008 is $56.48 per
22 megawatt-hour.
23 Q.Do you recommend any additional PCA
24 computational changes with the establishment of the new
25 PCA
420 SAID, DI 21
Idaho Power Company
.
.
16
1 regression formula?
2 A.Yes. There are two PCA computational factors
3 that need to be updated as a result of the current review
4 of power supply expenses. First, for PCA proj ection
5 calculations, a new normalized Base Power Cost must be
6 determined for inclusion in rate Schedule 55. Second, a
7 new Idaho jurisdictional percentage must be determined.
8 Q.Have you supervised the development of an
9 exhibi t to determine the PCA computational factors you
10 have just mentioned?
11 A.Yes. Exhibit No. 51 is a one-page exhibit
12 detailing the appropriate computation of the PCA factors
13 I have outlined.
14 Q. What is the first computation shown on Exhibit
15 No. 51?
A.The first computation details the normalized
17 Base Power Cost computation. The new normalized PCA
18 expense for the 2008 test year is $151.7 million compared
19 to the previous $128.0 million settlement value from the
20 2007 test year.
21 The normalized Base Power Cost is equal to the
22 $151.7 million normalized PCA expense divided by the
23 normalized system sales value of 14,465,151 MWh. The
24 resulting Base Power Cost is 1.04867 cents per kWh or.25
421 SAID, 01 22
Idaho Power Company
.
.
.
1 $10.49 per megawatt-hour.
2 Q.Please discuss the Idaho jurisdictional
3 percentage computation contained in Exhibit No. 51.
4 A.The Idaho jurisdictional firm load (15,036,726
5 MWh) divided by the system firm load number (15,863,628
6 MWh) results in an Idaho jurisdictional percentage of
7 94.8 percent. This is up from 94.7 percent in 2007 due
8 to a slightly higher growth rate in Idaho than in Oregon.
9 REVENU REQUIRENT ADJUSTMNTS
10 Q.Please describe your role in the preparation of
11 the Company's proposed 2008 revenue requirement.
12 A.As the Manager of Revenue Requirement, I
13 evaluated the concerns the parties in the IPC-E-07-08
14 rate case expressed with regard to the Company's
15 presentation of test year data in that case. Based upon
16 the parties' strongly expressed desire to have an
17 audi table starting point and explicit methods of
18 adj usting starting values to the test year, I directed
19 the Company's. efforts to respond to those requests. The
20 resul ts of those efforts are reflected in the exhibits of
2l Ms. Schwendiman. The auditable starting point is 2007
22 actual data. That data has been adjusted to reflect
23 normalized power supply expenses as approved in the 2007
24 case and to remove
25
422 SAID, DI 23
Idaho Power Company
.1 expenses that are typically not considered for ratemaking
2 purposes such as certain memberships or advertizing
3 expenses.
4 Given adjusted 2007 data, several methods are
5 then utilized to adjust historical 2007 data to test year
6 2008 levels. These methods have been primarily described
7 by Ms. Smith in her testimony in this case. The primary
8 methods used to adjust historical 2007 data to the 2008
9 test year include trending of plant investments less than
10 $2 million using a compound growth rate, using known and
11 measurable adjustments for plant investments of greater
12 that $2 million, and basing the growth of expenses and.13 revenues upon compound growth rates. I was part of the
l4 senior management team that assisted Ms. Smith in
15 developing these methods to adjust historical 2007 data
16 to 2008 test year levels.
17 Q.In addition to the methods of adjusting 2007
18 data to the 2008 levels described by Ms. Smith, are there
19 some specific methods for adjusting 2007 data to the 2008
20 test year that you provided to Ms. Schwendiman?
21 A.Yes~ I instructed Ms. Schwendiman to make
22 additional adjustments to reflect 2008 power supply
23 expenses, fuel inventories, imputed revenues for
24 annualizing adj ustments associated with plant additions.25
423 SAID, DI 24
Idaho Power Company
.
.
.
1 greater than $2 million, and contributions in aid of
2 construction ("CIAC"). I have previously described the
3 power supply expense levels that I instructed Ms.
4 Schwendiman to use.
5 Q.Please describe the fuel inventory adjustment
6 that you instructed Ms. Schwendiman to use.
7 A.I instructed Ms. Schwendiman to adj ust fuel
8 inventory dollars to reflect a 26-day inventory at the
9 Bridger Plant and 60-day inventories at both Valmy and
10 Boardman. Because Bridger is a mine-mouth plant, fewer
11 days of fuel inventory is required.
12 Q.Did you instruct Ms. Schwendiman to include
13 imputed revenue associated with annualized plant
14 addi tions of greater than $2 million?
15 A.Yes. The Commission in Order No. 29505 issued
16 in Case No. IPC-E-03-13 stated that "it is critical to
17 match revenues and expenses to these plant additions" in
.
18 reference to known and measurable additions. In Order
19 No. 29505, the Commission used a proxy for additional
20 revenues stating that the Company had "not adequately
2l quantified" such additional revenues. In its next rate
22 case, Case No. IPC-E-05-28, the Company introduced a
23 methodology for imputing revenues. The Company used this
24 same methodology in the preparation of its revenue
25 requirement in the next
424 SAID, DI 25
Idaho Power Company
.
.
.
1 rate case, Case No. IPC-E-07-08. Both cases were
2 settled. In its filing in this Case the Company has
3 included a quantification of revenues associated with
4 annualizing adjustments to transmission and distribution
5 plant determined in the same manner submitted in the 2005
6 and 2007 rate cases.
7 Q.Please describe the Company's method of
8 quantifying revenues associated with the annualizing
9 adj ustments to plant.
10 A.In order to estimate the additional revenues
11 that the Company would receive as a result of adding the
12 plant reflected in the annualizing adjustments, I
13 requested the preparation of Exhibit No. 52. Page 1 of
14 Exhibi t No. 52 shows the quantification of the revenue
15 credi t associated with the annualizing plant adj ustment.
16 Page 1 of Exhibit No. 52 shows the planned use of those
17 additional facilities annualized in the Company's 2008
18 test year. Based upon the system anticipated loads to be
19 served via those facilities by year end 2008 (128,479
20 MWh) and the system average revenue per MWh ($15.56 per
21 MWh), the imputed revenue associated with the annualized
22 transmission and distribution additions is $1,489,324 for
23 the Idaho jurisdiction. This is an approximate 11.6
24 percent reduction to the Idaho jurisdictional revenue
25 requirement
425 SAID, DI 26
Idaho Power Company
.1 resul ting from these additional investments. Most of the
2 annualized investments in this case are for the purposes
3 of system reliability, compliance, or environmental
4 improvement rather than being related to load growth.
5 Q.What instruction did you give Ms. Schwendiman
6 with regard to CIAC?
7 A.I instructed Ms. Schwendiman to adj ust actual
8 2007 CIAC to 2008 levels based upon the method used to
9 adj ust the corresponding plant investments for those
10 specific accounts from 2007 to 2008 levels. Ms. Smith
11 discusses the methods used to adjust plant financial
12 data..13
14
REVENU REQUIRENT OBSERVATIONS AN CONCLUSIONS
Q. Please summarize why Idaho Power Company is
15 utilizing a 2008 test year.
16 A.The fundamental reason that Idaho Power is
17 utilizing a 2008 test year is to address current concerns
18 regarding regulatory lag. In prior rate cases, rates
19 resulting from a test year were implemented five months
20 after completion of the test year (2003 test year rates
21 became effective June 1, 2004, and 2005 test year rates
22 became effective June 1, 2006). Rates implemented in
23 March 2008 were based upon a settlement stipulation that
24 did not specify a precise test year. A 2008 test year in.25 this case will allow for rates based upon a 2008 test
year to become
426 SAID, DI 27
Idaho Power Company
.1 effective early in 2009, shortly following the test year.
2 Q.In your opinion, given normal conditions in
3 2009, will implementing rates based upon a 2008 test year
4 allow the Company to earn its authorized rate of return
5 in 2009?
6 A.No. Based upon recent experience where the
7 Company is making large investments in all aspects of its
8 business at the same time that costs are rising, I do not
9 envision that revenues that the Company will receive
10 based upon a 2008 test year will keep pace with the
11 revenue requirements driven by investment levels and
12 expenses in 2009..13
14
15
16
17
18
19
20
21
22
23
24.25
Q.Does that conclude your testimony?
A.Yes, it does.
427 SAID, 01 28
Idaho Power Company
.
.
.
14
1 Q.Please state your name.
2 A.My name is Gregory W. Said.
3 Q.Are you the same Gregory W. Said that
4 previously submitted direct testimony in this proceeding?
5 A.Yes, I am.
6 Q.What is the purpose of your rebuttal testimony?
7 A.My rebuttal testimony will address what I
8 believe are fundamental flaws in the rationale supporting
9 the testimonies of Staff Witness Sterling and Micron
10 Wi tness Peseau with regard to power supply issues. I
11 will respond to Mr. Sterling's assertion that high gas
12 prices benefit Idaho Power's customers. I will also
13 respond to Mr. Sterling's testimony that focuses
exclusively on recommendations minimizing power supply
15 expenses included in base rates while making no effort to
16 identify the appropriate normalized level for power
17 supply expenses. I will address Micron Witness Peseau' s
18 apparent lack of understanding regarding the impact of
19 natural gas prices on modeled power supply expenses.
20 Q.Mr. . Sterling states on page 4 of his testimony
21 that "High gas prices actually benefit Idaho Power and
22 its ratepayers in most years." Is he correct?
23
24
25
428 SAID, DI REB 1
Idaho Power Company
.
.
.
1 A.No. High gas prices will not benefit Idaho
2 Power Company or its customers. Mr. Sterling relies on
3 test-year modeled power supply outcomes to arrive at
4 conclusions that are counter intui ti ve. Idaho Power's
5 current generating fleet includes 435 MW of simple cycle
6 gas-fired generating plants used primarily for provision
7 of power during peak load periods of time. In addition,
8 the Company is currently reviewing bids for up to 300 MW
9 of baseload gas-fired generation to be available in 2012.
10 It is misleading to suggest that the Company or its
11 customers will benefit from rising gas costs when
12 gas-fired generation will increasingly be required to
13 serve growing customer loads. The only way Mr. Sterling
14 can come to the conclusion that high natural gas prices
15 are good for customers is in the hypothetical world of
16 power supply modeling. In the real world, high natural
17 gas prices will cost customers more money as the Company
18 burns more gas to serve loads.
19 Q.What do you mean when you refer to the
20 hypothetical world of power supply modeling?
21 A.The' Company, the Commission Staff, and many
22 other utili ties in the Northwest use the AURORA model to
23 simulate power supply costs for ratemaking purposes. Gas
24 price assumptions included in AURORA power supply
25
429 SAID, DI REB 2
Idaho Power Company
.
.
1 simulations are a primary driver of modeled market prices
2 for electricity. Over the full range of water conditions
3 the Company has traditionally used to present its power
4 supply expenses on a "normal" basis, the Company's
5 modeling shows it will often have surplus energy to sell.
6 Stated another way, the normalized level of annual
7 surplus sales is 2.4 million MWh while the normalized
8 level of power purchased from the market is 0.5 million
9 MWh. In the modeling world, with a net surplus position,
10 higher electricity market prices will benefit sellers of
11 electricity provided that the surplus is generated by
12 resources modeled at cost less than the gas-fired
13 generation driving the modeled market prices for
14 electricity.
15 In the real world, as the Company's loads grow, less
16 and less surplus will be available from hydro generation
17 and more expensive coal-fired and natural gas-fired
18 resources will be utilized to a greater extent to serve
19 system loads. Short-run modeled surplus sales benefits
20 that result from high gas price-influenced electricity
21 market price will ultimately disappear as loads grow and
22 only the higher cost of fuel used to serve the growing
23 load will remain.
.24
25
430 SAID, DI REB 3
Idaho Power Company
.
.
.
1 Q.Does the AURORA power supply modeling
2 adequately reflect the impacts that Northwest hydro
3 condi tions can have on electricity market prices?
4 A.While the AURORA model does many things well,
5 one thing it does not do well is account for the impact
6 of regional hydro conditions when forecasting the market
7 prices Idaho Power will receive for its surplus sales.
8 The Company has repeatedly stated, and the Commission has
9 repeatedly recognized, that wi thin the Northwest, both
10 gas prices and hydro conditions are primary drivers of
11 market prices for electricity. i Low water conditions,
12 droughts, tend to drive electricity prices in the
13 Northwest up while abundant water tends to drive
14 electrici ty prices in the Northwest down. The Company
15 believes that AURORA modeling considers the gas price
16 influence on electricity market prices too heavily and
17 the water condition influence on electricity market price
18 too lightly.
19 Q.What has the Company done wi thin power supply
20 modeling to account for the influence of water conditions
21 on electricity market prices?
22 A.In order to correct for the modeling deficiency
23 in AURORA that fails to adequately reflect the
24
25
i Order No. 24806 issued in Case No. IPC-E-92-25 and Order No. 30047
issued in Case No. IPC-E-06-07 are two examples.
431 SAID, DI REB 4
Idaho Power Company
.
.
.
1 hydro condition influence on electricity market prices,
2 the Company has segmented water condition scenarios into
3 fi ve pentiles. Recognizing that the model primarily uses
4 gas prices to determine electricity prices, the Company
5 adjusts gas prices in each of the pentiles as a surrogate
6 for water condition influences on electricity prices.
7 Q.Mr. Sterling refers to Exhibit No. 102 that he
8 says demonstrates "there appears to be no correlation
9 whatsoever between Northwest hydro conditions and Sumas
10 gas prices on a monthly basis." Is this conclusion
11 misleading?
12 A.Yes. Idaho Power has never contended there is
l3 a correlation between Northwest hydro conditions and
14 Sumas gas prices. What Idaho Power has contended, and
15 still believes to be the case, is that Northwest hydro
16 condi tions influence electricity market prices. Because
17 the AURORA model does not adequately quantify this
18 influence, Idaho Power has corrected for the modeling
19 deficiency by modifying the model driver, gas price.
20 This modification is not made to suggest a correlation
21 between water condition and gas price, but rather to
22 reflect water. condition impacts on electricity market
23 prices. The
24
25
432 SAID, 01 REB 5
Idaho Power Company
.
.
19
1 Company has been open and forthright in stating this
2 position.2
3 Q.Does Mr. Sterling suggest that Northwest hydro
4 condi tions do not influence electricity market prices?
5 A.No. To the contrary, Mr. Sterling states that
6 gas prices and hydro conditions "both greatly influence
7 market prices." However, even though he recognizes the
8 importance of hydro conditions, Mr. Sterling provides no
9 assessment of the AURORA model capability to quantify the
10 impacts of hydro conditions on electricity market prices.
11 Rather than addressing the issue, he recommends the
12 elimination of the Company's attempt to correct for a
13 modeling deficiency based upon a mischaracterization of
14 the intent of the correction. As a result, he
15 understates the proper level of net power supply
16 expenses.
17 Q.What level of power supply expenses should the
18 Commission approve for inclusion in base rates?
A.The Commission should approve power supply
20 expenses as included in the Company's Application and
21 testimony in this case. The customer "benefits" from
22 high gas prices as quantified by Mr. Sterling are, in my
23
24.25
2 See pages 6 and 7 of Greg Said's direct testimony in Case No.
IPC-E-03-13.
433 SAID, DI REB 6
Idaho Power Company
.
.
1 opinion, an unfair reduction of reasonably expected power
2 supply expenses arising from an AURORA modeling
3 deficiency. I am concerned that Staff may be looking
4 solely for an opportunity to reduce the Company's revenue
5 requirement rather than make the effort needed to address
6 this deficiency in the AURORA model and thereby properly
7 quantify normalized power supply expenses.
8 Q.Did the Commission Staff, in a production
9 request, ask whether the Company had included the cost of
10 integrating wind projects in its power supply expense
11 quantification?
12 A.Yes. The Commission Staff's Production Request
13 No. 9 asked if the Company had included any wind
14 integration costs in this test year. The Company replied
15 that it had not included any wind integration costs in
16 the test year. The Company also stated that including
17 wind integration costs would add nearly $3.5 Million to
18 normalized power supply expenses. While the Staff
19 discovered the additional power supply expense the
20 Company failed to include in its case, Mr. Sterling has
21 not proposed to add the wind integration expense into
22 power supply expenses.
23 Q.Does the Company believe these wind integration
24 costs should be included in base rates?.25
434 SAID, DI REB 7
Idaho Power Company
.
.
.
1 A. Yes. The Company is currently bearing the
2 costs of integrating these proj ects into the system.The
3 costs of integrating wind proj ects into the system
4 include hourly operational impacts that are not easily
5 captured in AURORA modeling, such as the need for standby
6 generation from Company resources, increased purchased
7 power expenses, and reduced surplus sales. These costs
8 should appropriately be included in base rates.
9 Q.In addition to mischaracterizing the Company's
10 correction of a modeling deficiency and not adjusting
11 results to include additional power supply expenses
12 identified in discovery, is there anything else in Mr.
13 Sterling's testimony that suggests a goal of understating
14 the appropriate level of power supply expenses to be
15 included in base rates?
16 A.Yes. On page 15 of his testimony, Mr. Sterling
17 was asked "What happens if Idaho Power's actual net power
18 supply costs turn out to be different than those adopted
19 in this general rate case?" In his response, he states
20 "Idaho Power will never be at risk for more than 10
21 percent of the difference between projected power supply
22 costs and the base power supply costs." This response
23 concerns me because Mr. Sterling's statement suggests
24 that it does not matter if the Commission adopts base
25 power
435 SAID, DI REB 8
Idaho Power Company
.
.
.
1 supply expenses that are $10 million too low because the
2 Company will get $9 million back through the PCA. Such a
3 posi tion would be inconsistent with the intent of the
4 PCA. The PCA was intended to be symetrical, with the
5 Company giving back to customers during times of low
6 power supply expenses and recovering additional amounts
7 during times of high power supply expenses. If base
8 power supply expenses are purposely set too low, the
9 symetry and fundamental fairness of the process is lost.
10 During the last eight years, the Company has had power
11 supply expenses exceed the levels included in base rates
12 seven times. While this is largely a result of prolonged
13 drought, the Commission should be concerned about the
14 integri ty of PCA adj ustments over time.
15 Q.On page 15, line 7 of Dr. Peseau' s testimony,
16 he states "At the time Idaho Power prepared its testimony
17 in this case,' it used a March 2008 NYMEX natural gas
18 price forecast averaging about $10/mmbtu." Is this
19 statement accurate?
20 A.No. The Company did develop its natural gas
21 price forecast in March 2008; however, the methodology
22 was based on the inclusion of multiple natural gas price
23 indices, including NYMEX. The average natural gas price
24
25
436 SAID, DI REB 9
Idaho Power Company
.
.
1 used by the Company in the 2008 rate case is $7. 74/mmbtu,
2 not the $10/mmtu implied by Dr. Peseau.
3 Q.What average natural gas price did Mr. Sterling
4 propose?
5 A.Al though Mr. Sterling was critical of the
6 Company approach in arriving at $7. 74/mmtu, he proposes
7 using $7. 75/mmbtu. Dr. Peseau suggests that current
8 forecasts are for gas prices under $7. OO/mmtu.
9 Q.Dr. Peseau states that a 30 percent reduction
10 in gas prices will "of course, have a significant effect
11 on regional electricity prices and Idaho Power's net
12 power supply expenses for the test year." He goes on to
13 say that "I am sure, however, the use of the current
14 natural gas prices in the net power expense model would
15 eliminate all or a very substantial portion of the
16 forecasted increase in net power supply expenses."(P.
17 15, ll. 14-17.) Has Dr. Peseau accurately characterized
18 the affect of reduced natural gas prices modeled net
19 power supply expenses?
20 A.No. Dr. Peseau apparently does not understand
21 the current relationship between gas prices and modeled
22 net power expenses that both Mr. Sterling and I discussed
23 in our respective testimonies. Lower gas prices mean
24 lower market prices. In the power supply model, lower.25
437 SAID, DI REB 10
Idaho Power Company
.
.
18
1 market prices increase Idaho Power's net power supply
2 expense on a normalized basis. Higher natural gas price
3 assumptions input to the AURORA model result in higher
4 market surplus sales prices and thereby decrease Idaho
5 Power's net power supply expense on a normalized basis.
6 Q.Did the Company provide NYMEX future natural
7 gas prices to Dr. Peseau in its responses to Micron's
8 Production Requests Nos. 21-23?
9 A Yes.
10 Q.Were these natural gas prices higher or lower
11 than the Company's original natural gas price forecast
12 used in its test year?
13 A. The NYMEX natural gas prices provided to Dr.
14 Peseau based upon his specifications averaged
l5 $10.80/mmtu and $10.41/mmbtu, both higher than the
16 $7. 74/mmbtu used by the Company and both higher than the
17 below $7. OO/mmbtu stated in Dr. Peseau' s testimony.
Q.Dr. Peseau states that he requested power
19 supply model runs that would reflect the approximate
20 25-30 percent reduction in natural gas price forecasts.
21 Did Micron request power supply model runs with gas
22 prices 25 to 30 percent lower than in the Company's filed
23 case?
24.25
A.No. Micron requested runs using the NYMEX gas
prices provided by Idaho Power in response to Micron
438 SAID, DI REB 11
Idaho Power Company
.
.
.
1 production requests that I previously stated were
2 $10.80/mmbtu and $10. 41/mmbtu. These runs are contained
3 in Micron's Exhibit No. 704.
4 Q.Dr. Peseau testifies that his Exhibit No. 704
5 supports his argument that the Company's net power supply
6 expenses should be reduced by approximately $25 million
7 as shown in his Exhibit No. 704. Is he accurately
8 characterizing what Exhibit No. 704 shows?
9 A.No. Exhibit No. 704 shows the opposite affect
10 I just described. By increasing the natural gas prices
11 to the $10 per mmbtu level as requested by Dr. Peseau,
12 the Company's net power supply expenses went down just as
13 Mr. Sterling and I have testified.
14 Q. Have you prepared an exhibit to quantify a 10
15 percent reduction from the $7. 75/mmtu gas price
16 assumption included in the Company's filing?
17 A.Yes. Exhibi t No. 87 is AURORA output based
18 upon a reduction in gas price assumption from $7. 75/mmbtu
19 to $ 6.98 /mmbtu. Normalized net power supply expenses
20 rise from $88~ 4 million to $97.2 million.
21 Q.Dr. Peseau supports his argument for a
22 reduction in the Company's net power supply expenses by
23 comparing the PURPA avoided cost model to the model used
24 to
25
439 SAID, DI REB 12
Idaho Power Company
.
.
1 determine the Company's net power supply expense. Is
2 that a valid comparison?
3 A.No. The PURPA model predicts the fully
4 distributed cost of a hypothetical combined cycle
5 combustion turbine. It is intended to model the marginal
6 resource on the Company's system, i. e., the cost it can
7 "avoid. " It does not model the Company's net power
8 supply expenses. The 30 percent reduction in natural gas
9 prices cited by Dr. Peseau will reduce the cost of the
10 PURPA surrogate avoided resource. Lower gas prices have
11 the opposite affect on modeled net power supply expenses.
12 Q.Does the Company agree with Mr. Sterling's
13 natural gas price forecast of $7.7 5/mmtu, or the natural
14 gas price forecast over $10/mmtu contained in Dr.
15 Peseau' s Exhibit No. 704, but characterized by Dr. Peseau
16 as under $7/mmbtu?
17 A.Dr. Peseau is correct when he states that gas
18 prices have fallen. Both Mr. Sterling's and the
19 Company's natural gas price assumptions may be too high.
20 However, as I have stated earlier in my rebuttal
21 testimony, reducing the natural gas price assumptions
22 would increase the level of net power supply expenses.
23 Dr. Peseau' s conclusions regarding the changes in power
24 supply expenses
. 25
440 SAID, DI REB 13
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 that result from changes in gas prices are incorrect and
2 should be ignored.
3 Q.Does this conclude your rebuttal testimony?
4 A.Yes, it does.
5
6
7
8
9
441 SAID, DI REB 14
Idaho Power Company
.
.
.
1 (The following proceedings were had in
2 open hearing.)
3 MR. KLINE: With that, Mr. Said would be
4 available for cross.
5 COMMISSIONER SMITH: Mr. Ward, do you have
6 any questions?
7 MR. WARD: I do. Thank you.
8
9 CROSS-EXAMINATION
10
11 BY MR. WARD:
12 Q Just quickly, Mr. Said, just a
13 clarification item. You referred to your testimony on
14 page 20 about the LGAR recommendation. Just above that
15 on page 20 is a question and answer about the approved
16 LGAR rate. Do you see that question and answer? It's 8
17 through 13.
18
19
A Yes.
Q And you say, again, this is just
20 clarification, you say the Commission approved LGAR is
21 62.79 per megawatt-hour, but is only applied to one-half
22 of load growth making the rate effectively 31.40 per
23 megawatt-hour. The rate is not actually 31.40, is it?
24 It's just that we assume that the growth occurs evenly
25 and so the mid-year is the point at which we're selecting
CSB REPORTING
[phone]
442 SAID (X)
Idaho Power Company
.
.
19
20
1 the amount of load growth?
2 A No, it's not a mid-year computation. It's
3 one-half of any load that occurs in the year is applied
4 to the rate, so that's why I say it's effectively 31.40
5 because it's basically the 62. 79 divided by two.
6 Q I understand, but perhaps it's just
7 semantics, but it seems to me there's a possibility for
8 confusion here. It's not really a 31.40 rate. It's a
9 62. 79 rate applied to an assumption about the manner in
10 which that load growth occurs.
11 A It's one-half of the load growth, yes.
12 Q Okay. In your direct testimony, page 13,
13 lines 18 through 23, you say there that -- wait a minute,
l4 I gave you the wrong reference, I believe. Excuse me,
15 that's page 8, lines 8 through 11. There you're talking
16 about the normalized system load growth in this case and
17 you say it approximates 1.9 percent. Do you see that
18 testimony?
A Yes, I do.
Q Have you undertaken any study or other
21 effort to determine whether that 1.9 percent load growth
22 has in fact materialized?
.
23
24
25
A I have not reviewed that, no.
Q Gi ven the economic situation we find
ourselves in, wouldn't it be logical to assume that load
CSB REPORTING
[phone]
443 SAID (X)
Idaho Power Company
.
.
20
1 growth assumptions made early in this year are probably
2 not working out?
3 A I don't know that that's true.
4 Q That figure has some significance, does it
5 not, in that it is used in the compound annual growth
6 rate computation that's applied to a considerable segment
7 of the Company's expenses?
8 A The compound annual growth rates are
9 discussed by Ms. Smith; however, those compound annual
10 growth rates are based on financial numbers, not load
11 numbers.
12 Q Well, Mr. Said, I think what Ms. Smith
13 actually says is that for a significant segment of the
14 expenses that the compound annual growth rate is assumed
15 to equal system load growth plus a CPI inflator. You're
16 not aware of that?
17 A I think she talks about growth in
l8 expenses
19 Q Right.
A -- from a CPI perspective and growth in
21 expenses related to growth.
22 Q So wouldn't it be a fact that it has some
23 significance, does it not, whether in fact the growth
24 rate that you have assumed has actually materialized?.25 A And I think that when you look at the
CSB REPORTING
[phone]
444 SAID (X)
Idaho Power Company
.
.
.
1 expenses and the investments that have occurred in 2008
2 that Ms. Smith's testimony demonstrates that the amounts
3 that the Company estimated are very close to what has
4 happened in 2008.
5 Q Okay. Now, I want to later on in this
6 proceeding use your Exhibit No. 50 to discuss some issues
7 wi th another witness and what I would like to do since
8 you don't discuss that in great deal, I'd like to just
9 walk through that very quickly so the Commission can
10 understand what these, what this table means.
11 A Sure.
12 Q Okay, do you have Exhibit 50 in front of
13 you?
14 A I do.
15 Q All right. Now, in Exhibit No. 50, what
16 you are doing there is illustrating the manner in which
17 marginal energy costs are calculated; correct?
18 A That's correct.
19 Q And the purpose for this particular
20 marginal energy cost calculation?
21 A The Company was instructed to provide this
22 information as part of this filing.
23 Q Okay. Now, in reading that exhibit, if I
24 start with the top line, you'll see a 2008 energy total
25 and on across. First of all, that's the total energy
CSB REPORTING
[phone]
445 SAID (X)
Idaho Power Company
.
.
19
1 consumed per month in megawatt-hours, is it not?
2 A That's correct.
3 Q And down below there, you know, after the
4 first five lines, you see, again, another entry for 2008
5 and it says "Cost" and that cost is, again, the cost of
6 energy consumed in each of those months; correct?
7 A A little bit more precisely, that would be
8 the net power supply cost or expense for that month, so
9 it would include both fuel, purchased power and a net of
10 surplus sales.
11 Q You are correct, and it's probably stating
12 the obvious, but just so we can make sure there's no
13 misunderstanding, if you look at February, March and
14 April, you'll see there negative numbers; correct?
15 A Correct.
16 Q And would you explain to the Commission
17 how that occurs, how you get a negative net power supply
18 cost?
A Sure. In those months, the fuel expense
20 may be at a certain level and purchased power expense
21 would be added to that and then surplus sales would be
22 deducted from that, so in those instances, the dollars
23 received from surplus sales exceed the sum of fuel and
24 purchased power..25 Q And in a very crude sort of way, we can
CSB REPORTING
[phone]
446 SAID (X)
Idaho Power Company
.
.
19
20
1 see that those numbers generally correlate with spring
2 runoff; correct?
3 A Yes, they do.
4 Q And at the same time relatively lower
5 consumption on the system?
6 A Yes, and just to go back, they actually
7 precede the runoff period. The runoff is typically
8 thought to be April, so they precede it a little bit and
9 the loads are typically down in those months.
10 Q All right. Now, proceeding on down below
11 the columns we've just discussed is an area entitled,
12 "Base Case Plus 50 Megawatts." Do you see that?
13 A I do.
14 Q And in making -- would I be correct that
15 when you attempt to determine marginal costs, what the
16 Company does is it assumes a 50 megawatt increase in load
17 for each of those years in which you have a listing
18 there?
A Yes, for each hour wi thin the year.
Q Okay, and then you plug that information
21 into the AURORA model; correct?
22
23
A That's correct.
Q And it spits out the marginal cost of
24 energy that we see down below in the next set of.25 columns?
CSB REPORTING
[phone]
447 SAID (X)
Idaho Power Company
.
.
.
1 A The very next set of columns show the net
2 power supply costs by month for the case with 50
3 megawatts of additional load. The marginal costs are
4 then in the final section and are computed based upon the
5 difference of the costs shown in the base case plus 50
6 minus the additional costs or minus the costs from the
7 base and then those are divided by that 50 megawatt
8 increment.
9 Q Okay, and the end result, of course, is
10 you produce what the AURORA model calculates as the
11 marginal cost of energy for each month?
12
13
14
A Correct, under that methodology.
Q Okay. All right, as I said, I'll want to
use that later. I'm done with that. If you would turn
15 to your rebuttal testimony on -- let me find it here --
16 on page 1 of that testimony, at the bottom of the page
17 there's a question quoting Mr. Sterling in saying, "High
18 gas prices actually benefit Idaho Power and its
19 ratepayers in most years," and you're as ked whether he's
20 correct and you say on the top of the next page that he
21 is not, and then you go on to explain on page 2, really
22 throughout the page, that in the -- that the
23 Mr. Sterling's conclusion is correct only in the
24 hypothetical world of power supply modeling, but it is
25 counterintui ti ve and not correct in the real world;
CSB REPORTING
[phone]
448 SAID (X)
Idaho Power Company
.
.
.
i correct?
2 A That's correct.
3 Q And you say that's -- on page 4, lines 4
4 through 8, you say that's because the AURORA model
5 doesn't account well for real world hydro conditions; is
6 that also true?
7 A That's true.
8 Q And I take it, then, that what you did is
9 because you believe that the AURORA model does not
10 correctly account for hydro conditions, you made an
11 adj ustment to the actual gas prices that were input into
12 that model, did you not?
13 A We didn't input actual gas prices.We put
14 in a gas price forecast.
15 Q All right, but you adj usted -- well, page
16 5, lines 3 through 6 you say there, "Recognizing that the
17 model primarily uses gas prices to determine electricity
18 prices, the Company adjusts gas prices in each of the
19 pentiles as a surrogate for water condition influences on
20 electricity prices." Do you see that statement?
21
22
A I do.
Q I took that to mean that whatever gas
23 price information you would normally use, you adjusted or
24 modified to reflect what -- to produce what you believe
25 are outcomes that are more reflective of the real world.
CSB REPORTING
[phone]
449 SAID (X)
Idaho Power Company
.
.
.
1 A Electric market prices outcomes that are
2 more reflective of the real world, yes.
3 Q Okay, and what is it that you substituted
4 for what you would otherwise have input into that
5 model?
6 A What we did was we divided the 80
7 historical water conditions into five groups of 16 water
8 years and so for the bottom or the low water conditions,
9 we adj usted the gas price to a -- excuse me, let me think
10 a second. As gas price goes higher, then the impact of
11 that is that market prices for electricity are higher and
12 historically, we have found that market prices are higher
l3 under low water conditions, so for those 16 low water
14 condi tions, we adj usted the gas price higher to reflect
15 the water impact upon electric market prices and then
16 conversely, for high water conditions where electric
17 prices would typically be lower, we adj usted the gas
18 price to a lower level to drive the electric price to a
19 level that would be more reflective of the influence of
20 water.
21 Q Now, on page 6, you say the Company ha.s
22 been open and forthright about this alteration of the
23 model's inputs and results and that's at page 6 in the
24 footnote and you refer to pages 6 and 7 of your direct
25 testimony in support of that statement. I couldn't find
CSB REPORTING
[phone]
450 SAID (X)
Idaho Power Company
.
.
.
1 anything at pages 6 and 7 of your direct testimony that I
2 understood to be a disclosure of the changes you had made
to the model.Can you direct me to something?
A Did you look in the 3-13 case or this
case?
Q This case.
A The footnote says the 3-13 case.
Q Ah,you have me there,but that's not in
this case,is.it?
A No,I didn't discuss it in this case.It
3
4
5
6
7
8
9
10
11 was the methodology that was used in the 2003 case.
12 And that was five some years ago, was itQ
13 not?
14 The last time that this Commission hadA
15 hearings for a general rate case, yes.
16 Now, can I conclude from this that theQ
17 implici t argument you are making or one implicit argument
18 you are making is that when AURORA's modeled results
19 don't reflect the real world and produce counterintuitive
20 resul ts that the model should be rej ected or corrected?
21 I wouldn't say rejected, but if there areA
22 deficiencies in the model that can be corrected for by
23 adj usting the inputs, then I think that's something that
24 should be done.
25 Okay, on page 10 at line 20 on over on toQ
CSB REPORTING
[phone]
451 SAID (X)
Idaho Power Company
.1 page 11, you say, there you say, "Lower gas prices" -- at
2 23 -- "mean lower market prices," and you're stating that
3 in explanation of why you believe Dr. Peseau' s contention
4 about power supply is wrong.
5 A Yes, and that's a reference to lower gas
6 prices in the AURORA modeling result in lower electricity
7 market prices.
8 Q What I find interesting about that is
9 having critiqued Mr. Sterling's results at some great
10 lengths and said explicitly that he is in error in
11 contending that high gas prices benefit Idaho Power and
12 its ratepayers, you now cite Mr. Sterling as authority.13 for the proposition that lower gas prices mean lower
14 market prices and presumably don't benefit Idaho
15 ratepayers, so my question, among others, is how does
16 this compute? Higher prices don't help ratepayers and
17 lower prices don't help ratepayers.
18 A Well, the distinction that I make in my
19 testimony is that when you look at the scenario for a
20 test year and you're looking at a specific point in time,
21 Mr. Sterling is correct in the drivers of how net power
22 supply expenses move and as a result, when you look in
23 isolation at a modeled result that high gas prices do
24 benefi t customers in that context; however, when you look.25 at his statement that in most years this is a benefit to
CSB REPORTING
[phone]
452 SAID (X)
Idaho Power Company
.
.
.
1 customers, I think that's a false statement, because as
2 you move forward in time, surplus sales will naturally
3 reduce as loads grow, but resources don't.
4 The Company's next resource, base load
5 resource, is planned to be built in 2012 and as loads
6 grow between now and then, surplus sales levels will
7 decline as they did from last test year to this test
8 year. The difference in just a year was 600,000
9 megawatt-hours, so as you move forward in time, that
10 benefit that's derived by a point in time estimate goes
11 away to the detriment of customers and as a result, any
12 benefit that the model would show is immediately gone as
13 the loads grow.
14 Q But I don't see how it can be possible for
15 the converse not to be true as well; that is, if higher
16 prices are -- what you're really saying is in the long
17 run, higher prices are a detriment.
18 A Absolutely.
19 Q Then in the long run, don't lower prices
20 have to be a benefit?
21 A Yes, I think lower prices will be a
22 benefi t to customers in the long run.
23 Q All right, now, we're going to set rates
24 in this case for the year 2009. Which of those prospects
25 do we -- which criteria do we apply, the short run or the
CSB REPORTING
[phone]
453 SAID (X)
Idaho Power Company
.
.
20
21
22
23
24.25
1 long run?
2 A Well, in rate cases we typically look at a
3 snapshot in time and in this case that snapshot is the
4 2008 test year.
5 Q In that case, isn't it true that
6 Mr. Sterling would be correct?
7 A In the context of setting rates at a point
8 in time and this point in time having the situation where
9 Idaho Power is a net seller of surplus, then to any
10 extent that surplus sales can be valued at a level that's
11 higher than what the Company has proposed benefits
12 customers.
13 MR. WARD: That's all I have. Thank
14 you.
15 COMMISSIONER SMITH: Thank you, Mr. Ward.
16 Mr. Olsen.
17 MR. OLSEN: No questions.
18 COMMISSIONER SMITH: Mr. Purdy.
19 MR. PURDY: No questions. Thank you.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Thank you, Madam Chair.
CSB REPORTING
[phone]
454 SAID (X)
Idaho Power Company
.
.
20
1 CROSS-EXAMINATION
2
3 BY MR. RICHARDSON:
4 Q Sort of along the same lines of Mr. Ward,
5 so forgive me if we get a little redundant, I'll try not
6 to. In your rebuttal testimony, Mr. Said, you assert
7 that Mr. Sterling is focusing exclusively on
8 recommendations minimizing power supply expenses included
9 in base rates while making no effort to identify the
10 appropriate normalized level for power supply expenses.
11 Do you see that? That's on page 1, line 16.
12 A Yes, I see that.
13 Q Isn't it true that witness Sterling's
14 recommended net power supply expense of $77 million is
15 more than double the net power supply expense that was
16 adopted in Idaho Power's last general rate case in
17 2007?
18 A Are you looking at power supply expenses
19 excl uding PURPA?
Q I was just looking at Mr. Sterling's
21 Exhibit No. 106.
22 A I believe that's looking at just the fuel
23 and purchased power and surplus sales. I don't have that
24 in front of me, but I think a better reflection would be.25 total power supply expenses which include PURPA. I think
CSB REPORTING
[phone]
455 SAID (X)
Idaho Power Company
.
.
.
1 in both my testimony and Mr. Sterling's there's a
2 recogni tion that the amount of PURPA expenditures that
3 were included in the 2007 test year have been greatly
4 reduced in this case and as a result, the remaining power
5 supply costs have gone up considerably to reflect the
6 replacement power that would be required to make up for
7 the loss of those proj ects.
8 Q But the fact that Mr. Sterling recommended
9 a doubling in his testimony of the power supply costs for
10 this Company, does that suggest to you that Mr. Sterling
11 has indeed focused exclusively on recommendations to
12 minimize net power supply or that he perhaps has a
13 broader goal of understanding the Company's true power
14 supply expenses?
15 A Well, I would hope that Mr. Sterling's
16 desire is to arrive at the appropriate level of power
17 supply expenses. I've pointed to a couple of instances
18 where Mr. Sterling has adjusted the inputs to the power
19 supply modeling that basically increases the value of
20 energy or sets market prices higher during times when the
21 Company is surplus and that move market prices to lower
22 levels when the Company is purchasing. I think that both
23 of those end effects are as a result of trying to reduce
24 power supply expenses in his recommendation.
25 I also point to an example where the Staff
CSB REPORTING.
[phone]
456 SAID (X)
Idaho Power Company
.
.
.
i requested information as to whether or not the Company
2 had included costs associated with wind integration in
3 its power supply expenses. The Company responded that it
4 had not. Mr. Sterling was silent on that, which I think
5 is another demonstration that he may not be -- he may not
6 have included all of the costs that would be reasonably
7 considered.
8 Q And you are critical of Mr. Sterling for
9 not including wind integration costs in power supply
10 expenses? Are you aware that this Commission did not
11 allow wind integration costs to be included in the base
12 power supply expenses in Avista' s recently concluded
13 general rate case?
14 A I was not aware of that.
15 Q On page 3 of your rebuttal testimony at
16 line 19, you state that short-run modeled surplus sales
17 benefits that result from high gas price-influenced gas
18 electrici ty market price will ultimately disappear as
19 loads grow and only the higher cost of fuel used to serve
20 the growing load will remain. By stating the benefits
21 will ultimately disappear, aren't you conceding that the
22 benefits exist now?
23 A I am stating that the benefits appear in
24 the test year, but they immediately are deteriorated if
25 you move to 2009.
CSB REPORTING
[phone]
457 SAID (X)
Idaho Power Company
.
.
.
1 Q You may say that they're deteriorated, but
2 aren't the conditions that cause those benefits to occur,
3 the real world benefits as you put it, aren't those
4 condi tions likely to persist for at least as long the
5 rates established in this case will be in effect?
6 A No.
7 Q So there's going to be no surplus sales
8 benefits in 2009?
9 A There will be surplus sales benefits in
10 2009, but they will be less than what they have been in
11 2008.
12 Q But they would still exist; correct?
13 A The magnitude will change.
14 Q That wasn't my question. The question was
15 do the benefits still exist?
16 A There will always be a benefit when the
17 Company can sell surplus sales because they are only made
18 when the market price is higher than the cost of
19 generating the power.
20 Q And according to your model, the surplus
21 sales will exist then in 2009?
22
23
A In some hours of the year, yes.
Q Now, you use the AURORA model to determine
24 power supply costs in this case; correct?
25 A Yes.
CSB REPORTING
[phone]
458 SAID (X)
Idaho Power Company
.
.
.
1
2
Q Can you briefly,very briefly,describe
how that works for us?
A The AURORA model is set up to basically
look at the loads and the resources of the Company as
well as the loads and the resources of the region and
it's a dispatch model that dispatches the Company's
3
4
5
6
7 resources from least cost to most expensive resource with
8 the obj ecti ve of first serving Idaho jurisdictional loads
9 and our system loads and then determining whether or not
10 in any given hour there's a surplus or deficiency, and if
11 there's a deficiency, the model goes out and acquires
12 power, looks to see whether or not there is power
13 available and at what price, so the model does determine
14 a market price for electricity which both purchased power
15 and surplus sales are made.
16 Q So it would be fair to state that Idaho
17 Power relies on AURORA for a wide variety of important
18 decisions that the Company makes?
19
20
A Yes.
Q On page 4 of your rebuttal testimony at
21 lines 4 to 8, you discussed what you termed an AURORA
22 modeling deficiency by saying, "While the AURORA model
23 does many thipgs well, one thing it does not do well is
24 account for the impact of regional hydro conditions when
25 forecasting the market prices Idaho Power will receive
CSB REPORTING
[phone]
459 SAID (X)
Idaho Power Company
.
.
.
1 for its surplus sales," and then on line 14 of the same
2 page you state, "The Company believes that AURORA
3 modeling considers the gas price influence on electricity
4 market prices too heavily and the water condition
5 influence on electricity market price too lightly."
6 Since Idaho Power has such a high
7 percentage of its generation resources in hydro and is
8 adding a significant natural gas resource base, do you
9 think it's reasonable for this Commission to continue to
10 use a model that has such deficiencies on dealing with
11 hydro and gas resources?
12 A Yes, I think the model can be adjusted as
13 has been done by the Company in terms of modifying its
14 inputs and that provides reasonable results when that's
15 done.
16 Q Do you know of any other Northwest
17 utili ties that use AURORA that address this so-called
18 modeling deficiency you discuss by making the types of
19 corrections that you make?
20 A No, and I think that that's probably a
21 matter of the other utilities not having a similar
22 resource composition as Idaho Power, because, as you
23 pointed out, we are predominantly hydro and have been
24 predominantly hydro in our past. There are influences
25 related to water that other companies may not experience
CSB REPORTING
[phone]
460 SAID (X)
Idaho Power Company
.
.
.
1 to the degree that Idaho Power does and, therefore, the
2 deficiency that I've pointed out may not be as relevant
3 for their purposes.
4 Q Do you know whether EPIS, the developer of
5 the AURORA model, considers it to contain modeling
6 deficiencies as you suggest in this case?
7 A I know that it's aware of this modeling
8 deficiency because I discussed this issue with them in
9 2003 when we prepared the case and they were contributors
10 in providing us with a means of adjusting the inputs to
11 address the deficiencies that I identified.
12 Q And in order to correct AURORA's model
13 deficiency, you state that you have segmented water
14 condi tion scenarios into five pentiles and I think you
15 briefly went through with Mr. Ward how you did that , so
16 to summarize, I believe you matched low water conditions
17 wi th higher gas prices and high water conditions were
18 associated with lower gas prices; is that accurate?
19 A The only correction I would make is that
20 the association isn't as Mr. Sterling might characterize
21 based on a correlation of the relationship of water to
22 gas. They were explicit changes in the assumption of the
23 gas price with the sole intent of inj ecting water
24 influence into the ultimate determination of electric
25 market price.
CSB REPORTING
[phone]
461 SAID (X)
Idaho Power Company
.
.
.
1 Q So you're disavowing any suggestion that
2 water conditions in the Northwest drive natural gas
3 prices either up or down?
4 A I don't know of any correlation of gas
5 prices to water condition.
6 Q On page 8 of your rebuttal testimony,
7 beginning on line 16, you quote Mr. Sterling's testimony
8 where he asks, "What happens if Idaho Power's actual net
9 power supply costs turn out to be different than those
10 adopted in this general rate case?" You quote his
11 response as, "Idaho Power will never be at risk for more
12 than 10 percent of the difference between projected power
13 supply costs and the base power supply costs." Do you
14 see that testimony?
15 A I do.
16 Q Do you think it was significant that
17 Mr. Sterling used the words different and difference in
18 both his question and his response and doesn't that imply
19 that actual power supply costs could be either higher or
20 lower than proj ected power supply costs and that the PCA
21 is in fact a symmetrical ratemaking mechanism?
22 A Your statement about the power supply
23 expenses as being above or below a normalized base is
24 accurate. As. I point out in my testimony, Mr. Sterling
25 points out the example of the costs, that the Company
CSB REPORTING
[phone]
462 SAID (X)
Idaho Power Company
.
.
.
1 would be only at a risk of 10 percent which suggests to
2 me that he was thinking in terms of actual power supply
3 expenses being greater than the base that was
4 established.
5 Q But you would agree that Mr. Sterling was
6 accurate when he stated that Idaho Power will never be at
7 risk for more than 10 percent of the difference between
8 the proj ected power supply costs and the actual power
9 supply costs?
10 A Taking only into consideration the sharing
11 percentage in the mechanism, that would be correct.
12 There are other factors, such as the load growth
13 adjustment rate, that may influence whether or not that
14 percentage is higher or not.
15 MR. RICHARDSON: Thank you, Mr. Said.
16 Madam Chair, that's all I have.
17 COMMISSIONER SMITH: Thank you,
IB Mr. Richardson. Mr. Miller.
19
20
21
22
23
MR. MILLER: No questions.
COMMISSIONER SMITH: Mr. Bruder.
MR. BRUDER: No questions. Thank you.
COMMISSIONER SMITH: Mr. Price.
MR. PRICE: Thank you, Madam Chair. I
24 have a few questions.
25
CSB REPORTING
[phone]
463 SAID (X)
Idaho Power Company
.
.
1 CROSS-EXAMINATION
2
3 BY MR. PRICE:
4 Q To go back to the deficiencies that you
5 point out in the AURORA model, with regard to your
6 testimony, your rebuttal testimony, I believe it's on
7 page 6, that footnote, footnote 2, where you reference
8 your testimony in the IPC-E-03-13 case, and to your
9 recollection, did the Commission specifically approve the
10 methodology that you recommended in your testimony in
11 that case?
12 A I believe the Commission Order was silent
13 as to the methodology, but the numbers proposed by the
14 Company and the Staff were a direct result of the run
15 that the Company made in that case which did divide the
16 years into pentiles.
17 Q And the Staff opposed that testimony;
18 correct?
19 A No, Staff supported it and Mr. Sterling
20 said that, if anything, the Company's recommendation
21 might have been conservative.
22 Q Well, maybe there's confusion here, Mr.
23 Said. Didn't Staff oppose the methodology if not what
24 you're referring to as the overall net power supply cost,.25 the methodology which you used to arrive at it?
CSB REPORTING
[phone]
464 SAID (X)
Idaho Power Company
.
.
20
1 A I don't remember Staff commenting on
2 pentiles.
3 Q And that case was settled?
4 A No, it was not.
5 Q It went to hearing?
6 A It did.
7 Q And going to the AURORA model, again,
8 about the deficiencies, doesn't the AURORA model consider
9 all water conditions, not just high water, not just low
10 water, but it does account for all water conditions?
11 A It considers 80 water conditions in this
12 current case and in the past it's been less, but as years
13 have passed they've been added.
14 Q And you said that you informed EPIS about
15 the deficiencies that you discovered in the Aurora
16 model?
l7 A I did.
18 Q And they haven't done anything to correct
19 those deficiencies?
A As I stated in my testimony earlier, they
21 worked with the Company to develop the algorithm that
22 would divide and segment the pricing into pentiles and
23 that's the methodology that we used in the 2003 case.
24.25
Q And the AURORA model forecasts prices or
market prices in the Northwest, correct, specifically in
CSB REPORTING
[phone]
465 SAID (X)
Idaho Power Company
.
.
.
1 the Northwest?
2 A Well, for the modeling that we look at,
3 it's the price that ultimately Idaho Power would see, but
4 generally, yes, it's for the whole region.
5 Q And to the extent that other companies are
6 using this AURORA model, they haven't advised EPIS of the
7 deficiency, EPIS is not working with them, to the extent
8 that they're using that model that they're receiving
9 incorrect or erroneous power supply costs?
10 A Well, as I stated earlier, their
11 indi vidual impacts of water on their, on the market
12 prices that they see may not be identical to what Idaho
13 Power sees and I don't know that they necessarily are
l4 using the modeling in exactly the same context that we
15 may be using it, so EPIS has not made a generic change to
16 their model that would be applicable and used by all of
17 their clients, but they are aware of the modification
18 that they helped us develop for our purposes.
19 Q And you have made them aware, as you said,
20 of these deficiencies. Is it your testimony here today
21 that the Commission should continue to use the AURORA
22 model and that the Company should be allowed to make
23 reasonable adj ustments?
24
25
A In every rate case the modeling is
presented and. the inputs are reviewed and I believe that
CSB REPORTING
[phone]
466 SAID (X)
Idaho Power Company
.
.
1 AURORA is an adequate model to use for the determination
2 of power supply expenses and that in the instance of the
3 input adjustments proposed by the Company that they
4 should be recognized and approved as well.
5 Q Should there be a standard for the types
6 of adj ustments that would be allowed to enter into the
7 AURORA model? Should the Commission establish a set of
8 standards?
9 A I don't know that the Commission would
10 want to look at every input to the modeling and specify
11 exactly how that input is determined. I think they rely
12 on the technical Staff of the Commission Staff and the
13 parties to review and comment on those particular
14 inputs.
15 Q Are when you say "inputs," could you
16 clarify that? My understanding is it's not actually
17 input but a tweaking of the model, it's not an actual
18 input into the model.
19 A No, it's an input. It's not the model
20 itself, so in this instance, there are five inputs rather
21 than one for gas price. There's a gas price input for
22 the lowest 16 years, one for the next 16 years, one for
23 the middle 16 years, so basically there are five inputs
24 as proposed by the Company as opposed to one proposed by.25 Mr. Sterling. Then the modeling itself will take the
CSB REPORTING
[phone]
467 SAID (X)
Idaho Power Company
.
.
.
1 actual conditions that occur in any given month and
2 adj ust prices based on resource and load balance in that
3 time period.
4 MR. PRICE: I don't have anything
5 further.
6 COMMISSIONER SMITH: Thank you. Do we
7 have any questions from the Commission?
8 COMMISSIONER KEMPTON: I have one.
9 COMMISSIONER SMITH: Commissioner
10 Kempton.
11
12 EXAMINATION
13
14 BY COMMISSIONER KEMPTON:
15 Q The question I have is tied in, it's one
16 small piece I think that's still missing in what's been
17 addressed so far this afternoon and it has, again, to do
18 wi th your rebuttal to Mr. Sterling when on page 6 on
19 item, line item, 6, actually the question is line 3, the
20 question is, "Does Mr. Sterling suggest that Northwest
21 hydro conditions do not influence electricity market
22 prices?" You respond, "No. To the contrary,
23 Mr. Sterling states that gas prices and hydro conditions
24 'both greatly influence market prices.'" Then you go on
25 to say, "However, even though he recognizes the
CSB REPORTING
[phone]
468 SAID (Com)
Idaho Power Company
.
.
.
1 importance of hydro conditions, Mr. Sterling provides no
2 assessment of the AURORA model capability to quantify the
3 impacts of hydro conditions on electricity market
4 prices. " What you don't add is the sentence that came
5 right after the fact that Mr. Sterling did say that they
6 both greatly influence market prices and he said, "They
7 do so independently."
8 Would that make a difference to your
9 conclusion, then, in once again criticizing Mr. Sterling
10 when he did not provide an assessment of the AURORA model
11 capabili ty to quantify the impacts of hydro conditions on
12 electrici ty market prices?
13 A No, I agree with Mr. Sterling that they
14 have independent impacts, but the modeling doesn't
15 capture both of those impacts and so in order to correct
16 for the fact that the hydro influence on market prices
17 isn't adequately addressed, the only option available is
18 to adjust the input that does affect market price in the
19 modeling and that's gas price, so I agree with
20 Mr. Sterling that the two are independent, the gas price
21 influence and water influence are independent, but the
22 modeling doesn't treat the two independently and,
23 therefore, the way to correct for that is to adjust the
24 gas price to try and demonstrate the influence of
25 water.
CSB REPORTING
[phone]
469 SAID (Com)
Idaho Power Company
.
.
.
15
1 Q And since this is an Idaho Power rate
2 case, it would be your responsibility to do that
3 modeling, I would assume, rather than Mr. Sterling?
4 A Mr. Sterling has access to the modeling
5 and obviously has reviewed the Company's filings in the
6 past, so it is incumbent upon him to provide input to the
7 Commission when he believes that something should be
8 treated in a different manner than the Company, so I'm
9 not suggesting that the Company presents something and no
10 one else can comment. All I am trying to point out is
11 that I think Mr. Sterling attributes the correction to
12 the deficiency that I've talked about not only in this
13 case but in the past and he characterizes it as being a
14 correlation which isn't the case.
Q When you speak to the past, are you
16 talking about the influence of the hydro conditions on
17 the electric market price?
18 A I'm speaking as to how the Commission has
19 viewed the modeling to determine electric market prices
20 in the past. In the 2003 case, the methodology that
21 ultimately was not explicitly approved but approved in
22 terms of the ultimate results reflected five gas price
23 inputs. The two cases subsequent to that have been
24 settled and so they haven't been reviewed by the
25 Commission and, therefore, no additional discussion has
CSB REPORTING
[phone]
470 SAID (Com)
Idaho Power Company
.1 been afforded for your review.
2 Q Okay, then on page 4 on line '14 where you
3 say, "The Company believes," I will assume that's past
4 tense in some of the past considerations that you've
5 made, "that AURORA modeling considers the gas price
6 influence on electricity market prices too heavily and
7 the water condition influence on electricity market price
8 too lightly" that you've actually done that modeling and
9 would have that to present to the Commission from past
10 modeling?
11 A There's a li ttle bit of subj ecti vi ty that
12 takes place when you ask that question. Mr. Sterling in.13 his testimony talks about the difficulty of testing a
14 model to see whether or not it accurately reflects
15 condi tions due to the fact that in a test year, you're
16 moving everything to current condition rather than what
17 actually happened in a historical period of time, so
18 there is a little bit of difficulty in quantifying how
19 the gas or how the water price influence is reflected in
20 modeling.
21 I think by comparing the run prepared by
22 the Company and the run prepared by Mr. Sterling, you can
23 see that there is an $8 million difference in the
24 quantification, but beyond that, you need to go into the.25 indi vidual historical conditions and look to see whether
CSB REPORTING
[phone]
471 SAID (Com)
Idaho Power Company
.
.
.
20
1 those prices and the variation of price in that
2 historical condition aligns with what has happened in the
3 past. With Mr. Sterling's results if you were to do
4 that, you would see that market prices are somewhat
5 condensed. They have a range that isn't as broad as the
6 range that's contained in the Company's filing and I
7 would state that if you went back and looked at
8 historically what has actually happened in the past that
9 you would see variation in market prices that are better
10 reflected with the Company's results than Mr.Sterling's.
COMMISSIONER KEMPTON:Thank you.
THE WITNESS:You're welcome.
COMMISSIONER SMITH:Commissioner Redford.
COMMISSIONER REDFORD:Thank you,
11
12
13
14
15 Madam Chairman.
16
17 EXAMINATION
18
19 BY COMMISSIONER REDFORD:
Q Wi th regard to AURORA again, so the
21 Company prepared an AURORA run?
22
23
A Correct.
Q And the Commission prepared an AURORA
24 run?
25 A Correct.
CSB REPORTING
[phone]
472 SAID (Com)
Idaho Power Company
.
.
.
1 Q And you used five different adjustments?
2 A We used five different gas prices.
3 Q Gas prices, and Mr. Sterling, would you
4 comment, did he use one?
5 A He used one.
6 Q Okay; so there would naturally be a result
7 that's different?
8 A Correct.
9 Q And so since the AURORA model won't give
10 you the accurate numbers that you believe exist, you
11 force, in effect you force, the AURORA to accept new data
12 to come out with a predetermined result?
13
14
A No, I wouldn't say that that's the case.
Basically, what we have identified and what we believe to
15 be the case is that water has an influence on electric
16 market price that's not reflected in the computations
17 contained in the AURORA model, so in order to reflect the
l8 fact that water does have an influence, we tried to
19 divide that influence into pieces and show that there
20 would be a -- that in a high water condition, market
21 prices would drop to level below those that would occur
22 wi th a single gas price input, and that with low water
23 condi tions, market prices would go higher than a single
24 gas price input would demonstrate.
25 Q So there is a difference of opinion
CSB REPORTING
[phone]
473 SAID (Com)
Idaho Power Company
.
.
.
1 between you and the Staff?
2 A Absolutely.
3 Q Do you ever get together and try to
4 reconcile the numbers?
5 A There has been a number of discussions
6 over the years as to appropriate modeling inputs. We
7 have had conversations with the Staff on this. As part
8 of our PCA discussions, there was concern that base power
9 supply expenses were historically too low and from my
10 perspective, I thought that was recognition on the part
11 of the Staff that there may be deficiencies in the AURORA
12 modeling that result in power supply, normalized power
13 supply, expenses being set too low.
14 Q And did you discuss that with the Staff?
15 A Yes.
16 Q Okay. You've also stated, and I don't
17 recall what page it was, that Mr. Sterling apparently
18 didn't include wind integration costs in the power supply
19 costs.
20 A That's correct. The Company didn't
21 either.
22 Q Is that because AURORA won't take it into
23 consideration?
24
25
A There were a number of workshops to
address the effects of wind integration and the costs
CSB REPORTING
[phone]
474 SAID (Com)
Idaho Power Company
.
.
.
1 associated with wind integration and during those
2 workshops, it was determined that AURORA was not the best
3 model to determine those costs and so the Company used
4 some other modeling that was available to quantify those
5 impacts, so that was an instance where wind in
6 particular, those types of resources, and the hourly
7 variation of output from those, the impact that that may
8 have on power supply costs, those weren't totally
9 captured in the AURORA modeling either.
10 Q It seemed to me your testimony was a
11 little critical of Mr. Sterling because he didn't include
12 wind integration costs in the power supply cost and yet,
13 you now tell me you didn't do it either.
14 A The question that was posed was did the
15 Company include those costs. Our response was no, we
16 forgot, quite frankly. We had stated in testimony
17 previously that we would include those costs in a future
18 rate case and in the preparation of the case, it was
19 something that we forgot to do, so when we, got the
20 question, we thought ah hah, someone did remember and we
21 thought that that would be reflected in his testimony.
22 Q Could it be a reason that you don't know
23 what wind integration costs actually are?
24
25
A Well, I think the way we determined the
wind integration cost is that we took the results of that
CSB REPORTING
[phone]
475 SAID (Com)
Idaho Power Company
.
.
1 workshop and a specific rate per kilowatt-hour or
2 megawatt-hour was determined as part of that workshop and
3 so we took that rate and multiplied it by the wind
4 generation megawatt numbers to come up with the $3.5
5 million, I believe, of wind integration costs.
6 Q In your wind integration agreements, don't
7 you have a price that includes the wind integration
8 costs; that is, a lessor price because you charge the
9 wind integration costs to the supplier?
10 A I believe that's correct.
11 Q Shouldn't that be indicative of what the
12 wind integration costs are?
13 A I believe the same rate was used for that
14 determination as our response in the data request.
15 Q How do you calculate wind integration
16 absent those agreements which I believe were probably
17 arbi trary numbers?
18 A Well, I believe that in each of the
19 contracts that we have with the wind generators, they
20 specify what their output will be.
21 Q Okay, let's assume that the agreement
22 didn't provide that, how do you calculate, then,
23 Company-wide wind integration costs as a part of the
24 power supply costs?.25 A They are not captured in the AURORA model.
CSB REPORTING
[phone]
476 SAID (Com)
Idaho Power Company
.
.
.
20
1 They are totally captured outside by that other process
2 and I'm not totally familiar with how that's
3 quantified.
4 Q You don't know what the elements of the
5 costs are?
6 A Well, the elements of the costs are that
7 due to the fluctuation and output that occurs with a wind
8 facili ty that there are hourly impacts on the dispatch of
9 other Company resources to meet loads at any given time,
10 so if a wind project is producing 100 megawatts in one
11 hour and then dropping down to five or ten, there's a
12 sudden drop that requires that another resource be fired
13 up to make up for that loss of generation, so the
14 modeling that was done in conj unction with those
15 workshops was trying to look at those hourly impacts on
16 the system and the resources that might be required to
17 replace wind generation when it fell off.
18 COMMISSIONER REDFORD:I don't have any
19 further questions, Madam Chairman.
COMMISSIONER SMITH: I don't think I do
21 either. Mr. Kline.
22
23
24
25
CSB REPORTING
[phone]
477 SAID (Com)
Idaho Power Company
.
.
20
21
1 REDIRECT EXAMINATION
2
3 BY MR. KLINE:
4 Q I just have one, Mr. Said. In the
5 discussion that you had with Commissioner Redford about
6 the wind integration costs, the wind integration costs
7 that you should have used to come up with the
8 three-and-a-half million dollar amount that's set out in
9 your testimony, those costs were approved by this
10 Commission, were they not?
11 A They were.
12 MR. KLINE: That's all I have.
13 COMMISSIONER SMITH: Thank you for your
14 help, Mr. Said.
15 THE WITNESS: Thank you.
16 (The witness left the stand.)
17 COMMISSIONER SMITH: I think we need to
18 take a little break here. How about 10 after 3:00.
19 (Recess. )
COMMISSIONER SMITH: Mr. Walker.
MR. WALKER: Thank you. Idaho Power calls
22 as its next witness Mr. Timothy Tatum.
23
24.25
CSB REPORTING
[phone]
SAID (Di)
Idaho Power Company
478
.1
2
TIMOTHY E. TATUM,
produced as a witness at the instance of the Idaho Power
3 Company, having been first duly sworn, was examined and
4 testified as follows:
5
6
7
8 BY MR. WALKER:
9 Q
DIRECT EXAMINATION
Could you please state your name and spell
10 your last name for the record?
.
11 A Timothy E. Tatum. Last name is T-a-t-u-m.
And by whom are you employed and in what
I'm employed by Idaho Power Company. I'm
15 the manager of customer or cost of service.
12 Q
And are you the same Timothy Tatum that
17 filed direct testimony on June 27th, 2008 and prepared
13 capacity?
18 Exhibit Nos. 53 through 71?
20
14 A
Yes, I am.
And did you also file rebuttal testimony
21 on December 3rd?
22
23
16 Q
Yes, I did.
Do you have any corrections or changes or
24 clarifications to your testimony or exhibits?.25
19 A
Just one, actually. If you go to page 1
Q
A
Q
A
CSB REPORTING
[phone]
479 TATUM (Di)
Idaho Power Company
.
.
.
1 of my direct testimony, I would just simply like to
2 change my title. I was promoted to manager of cost of
3 service in September of 2008, so line 7 should be changed
4 to reflect my new title.
5 Q If I were to ask you the questions set out
6 in your corrected prefiled testimony, would your answers
7 be the same here today?
8 A Yes.
9 Q Both your direct and your rebuttal?
10 A Correct.
11 MR. WALKER: I move that the prefiled
12 direct and rebuttal testimony of Timothy Tatum be spread
13 upon the record as if read and that his Exhibits 53
14 through 71 be marked for identification.
15 COMMISSIONER SMITH: Without obj ection, it
16 is so ordered.
17 (The following prefiled direct and
18 rebuttal testimony of Mr. Timothy Tatum is spread upon
19 the record.)
20
21
22
23
24
25
CSB REPORTING
[phone]
480 TATUM (Di)
Idaho Power Company
.
.
.
1 Q.Please state your name and business address.
2 A.My name is Timothy E. Tatum and my business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what capacity?
5 A.I am employed by Idaho Power Company
6 ("Company") as Manager of Cost of Service in the Pricing
7 and Regulatory Services Department.
8 Q .Please describe your educational background.
9 A.I received a Bachelor of Business
10 Administration degree in Economics from Boise State
11 University in 2001. In 2005, I earned a Master of
12 Business Administration degree from Boise State
13 Uni versi ty. I have also attended electric utility
14 ratemaking courses including "Practical Skills for the
15 Changing Electrical Industry," a course offered through
16 New Mexico State Uni versi ty' s Center for Public
17 Utili ties, "Introduction to Rate Design and Cost of
18 Service Concepts and Techniques" presented by Electric
19 Utili ties Consultants, Inc., and Edison Electric
20 Institute's "Electric Rates Advanced Course."
21 Q.Please describe your work experience with Idaho
22 Power Company.
23 A.I became employed by Idaho Power Company in
24 1996 as a Customer Service Representative in the
25 Company's
481 TATUM, DI 1
Idaho Power Company
.
.
.
1 Customer Service Center. In June of 2003, after seven
2 years in customer service, I began working as an Economic
3 Analyst on the Energy Efficiency Team. As an Economic
4 Analyst, I maintained proper accounting for Demand-Side
5 Management ("DSM") expenditures, prepared and reported
6 DSM program accounting and acti vi ty to management and
7 various external stakeholders, conducted cost-benefit
8 analyses of DSM programs, and provided DSM analysis
9 support for the Company's 2004 Integrated Resource Plan
10 ("IRP") .
11 In August of 2004, I accepted a position as a
12 Pricing Analyst in Pricing and Regulatory Services. As a
13 Pricing Analyst, I provided support for the Company's
14 various regulatory acti vi ties including tariff
15 administration, regulatory ratemaking and compliance
16 filings, and the development of various pricing
17 strategies and policies.
18 In August of 2006, I was promoted to Senior
19 Pricing Analyst. As a Senior Pricing Analyst, my
20 responsibilities have expanded to include the development
21 of complex financial studies to determine revenue
22 recovery and pricing strategies. In 2007, I prepared the
23 Company's cost-of-service study submitted as part of Case
24 No. IPC-E-07-08 and served as the Company's
25 cost-of-service witness in that case.
482 TATUM, DI 2
Idaho Power Company
.
.
.
1 Q.What is the scope of your testimony in this
2 proceeding?
3 A.My testimony will address the Company's class
4 cost-of-service studies and the allocation of revenue
5 requirement. My testimony will also address the
6 derivation of the Fixed Cost per Customer ("FCC") and
7 Fixed Cost per Energy ("FCE") rates to be used in
8 determining the annual Fixed Cost Adj ustment ("FCA")
9 under Schedule 54, Fixed Cost Adj ustment.
10 CLASS COST-OF-SERVICE STUDY OVERVIEW
11 Q.How many cost-of-service studies have you
12 prepared as part of this general rate case proceeding?
13 A. I have prepared three cost-of-service studies
14 as part of this general rate case proceeding.
15 Q.Please describe in general terms the process
16 used to prepare the three class cost-of-service studies.
17 A.There are two general steps used in preparing a
18 class cost-of-service study. The first step is to
19 determine the total costs of providing electric service,
20 adj usted for normal weather and water conditions. These
21 costs have been provided to me by Ms. Schwendiman on
22 Exhibi t No. 46. The next step is to establish a
23 methodology for the separation of those costs among
24 customer classes.
25
483 TATUM, DI 3
Idaho Power Company
.
.
.
13
14
1 Q.What methodology is used to separate costs
2 among customer classes?
3 A.The methodology for separating costs among
4 classes consists of a three-step process generally
5 referred to as classification, functionalization, and
6 allocation. In all three steps, recognition is given to
7 the way in which the costs are incurred by relating these
8 costs to the way in which the utility is operated to
9 provide electrical service.
lO Q.Please explain the meaning of classification.
11 A.Classification refers to the identification of
12 a cost as being either customer-related, demand related,
or energy-related. These three cost components are used
to reflect the fact that an electric utility makes
15 service available to customers on a continuous basis,
16 provides as much service, or capacity, as the customer
17 desires at any point in time, and supplies energy, which
18 provides the customer the ability to do useful work over
19 an extended period of time. These three concepts of
20 availabili ty, capacity, and energy are related to the
21 three components of cost designated as customer, demand,
22 and energy components , respectively. In order to
23 classify a particular cost by component, primary
24 attention is given to whether the cost
25
484 TATUM, DI 4
Idaho Power Company
.
.
.
1 varies as a result of changes in the number of customers,
2 changes in demand imposed by the customers, or changes in
3 energy used by the customers.
4 Q.What are some examples of customer , demand-
5 and energy-related costs?
6 A.Examples of customer related costs are the
7 plant investments and expenses that are associated with
8 meters and service drops, meter reading, billing and
9 collection, and customer information and services as well
10 as a portion of the investment in the distribution
11 system. These investments and expenses are made and
12 incurred based on the number of customers, regardless of
13 the amount of energy used, and are therefore generally
14 considered to be fixed costs. Demand-related costs are
15 investments in generation, transmission, and a portion of
16 the distribution plant and the associated operation and
17 maintenance expenses necessary to accommodate the maximum
18 demand imposed on the Company's system. Energy-related
19 costs are generally the variable costs associated with
20 the operation of the generating plants, such as fuel.
21 However, due to the hydro production capability of the
22 Company, a portion of the hydro and thermal generating
23 plant investment has historically been classified as
24 energy-related.
25
485 TATUM, DI 5
Idaho Power Company
.
.
.
1 Q.What did you use as your primary guide in
2 classifying costs as either customer-, demand-, or
3 energy-related?
4 A.I used the Electric Utility Cost Allocation
5 Manual published, January 1992, by the National
6 Association of Regulatory Utility Commissioners as my
7 primary guide to the classification of customer-,
8 demand-, and energy-related costs.
9 Q.Please explain the meaning of
10 functionalization.
11 A.In addition to classification, costs must be
12 functionalized; that is, identified with utility
13 operating functions. Operating functions recognize the
14 different roles played by the various facilities in the
15 electric utility system. In the Company's accounts,
16 these various roles are already recognized to some
17 degree, particularly in the recording of plant costs as
18 production-, transmission-, or distribution-related.
19 However, this functional breakdown is not in sufficient
20 detail for cost-of-service purposes . Individual plant
21 items are examined and, where possible, the associated
22 investment costs are assigned to one or more operating
23 functions, such as substations, primary lines, secondary
24 lines and meters. This level of functionalization allows
25 costs to be more
486 TATUM, DI 6
Idaho Power Company
.
.
.
14
1 equi tably allocated among classes of customers.
2 Q.Please explain the process of allocation.
3 A.The process of allocation is merely one of
4 apportioning the total jurisdictional cost among classes
5 by introducing allocation factors into the process. An
6 allocation factor is nothing more than an array of
7 numbers which specifies the class value or share of a
8 total j urisdictional quantity.
9 Once individual costs have been allocated to
10 the various classes of service, it is possible to total
11 these costs as allocated and arrive at a breakdown of
12 utili ty rate base and expenses by class. The results are
13 stated in a summary form to measure adequacy of revenues
for each class. The measure of adequacy is typically the
15 rate of return earned on rate base compared to the
16 requested rate of return.
17 Q.Please provide a general overview of the class
18 cost-of-service model.
19 A.The class cost-of-service model is comprised of
20 two separate Microsoft Excel workbooks. The first
21 workbook, called the Assign Module, performs the
22 classification and functionalization processes I
23 described earlier. This workbook categorizes the Idaho
24 jurisdictional costs identified by FERC account into
25
487 TATUM, DI 7
Idaho Power Company
.
.
.
19
1 operating functions, such as production, transmission,
2 distribution, metering, customer service, etc. It also
3 categorizes the functional costs into demand-, energy-,
4 and customer-related classifications. For example, the
5 Assign Module categorizes the Company's investment in
6 steam plant into the production function and the demand-
7 and energy-related classifications.
8 The second workbook, called the Functionalized
9 Cost Module, or "FC Module" for short, performs the class
10 allocation process. This module allocates the classified
11 and functionalized costs developed in the Assign Module
12 to the various customer classes. For example, the FC
13 Module allocates the demand- and energy-related
14 production costs identified in the Assign Module to each
15 of the Company's customer classes and special contract
16 customers. Each of the major operations performed by
17 this module is shown as a separate worksheet to make the
18 allocation process transparent and easy to understand.
Q.Has the overall design of the class
20 cost-of-service model remained unchanged since the
21 Company's last general rate proceeding?
22 A.Yes. The overall design and functionality of
23 the model remains unchanged since the last general rate
24 case proceeding. However, some minor modifications have
25
488 TATUM, DI 8
Idaho Power Company
.
.
.
1 been made to the logic and the placement of worksheets
2 within the Assign Module in an effort to enhance the
3 transparency of the process.
4 PREVIOUS MODIFICATIONS TO
THE SYSTEM COINCIDENT DEM METHODOLOGY
5
6 Q.In the Company's 2005 general rate case
7 proceeding, Case No. IPC-E-05-28, two changes were made
8 to the methodology used to prepare the system coincident
9 demands used in the allocation of fixed generation and
10 transmission costs. Will you please review the nature of
11 those changes?
12 A.Yes. In Order No. 29505 issued in the
13 Company's 2003 general rate proceeding, Case No.
14 IPC-E-03-13 (" 03-13 Case"), the Commission opened Case
15 No. IPC-E-04-23 for the purpose of evaluating
16 cost-of-service issues raised during that general rate
17 proceeding. Three "cost-of-service" workshops were held
18 wi th interested parties between November 2004 and
19 February 2005~ During the workshop discussions, Idaho
20 Power committed to revise the methodology used to convert
21 billing period data to calendar month data and to prepare
22 two cost-of-service studies as part of its next general
23 rate case filing, one using a surrogate for a demand
24 normalization methodology and one using the traditional
25 methodology. Idaho Power fulfilled
489 TATUM, DI 9
Idaho Power Company
.
.
.
1 that commitment in Case No. IPC-E-05-28 ("05-28 Case").
2 Q. Was the "workshop methodology" for converting
3 billing period data to calendar month data also used in
4 the current rate case proceeding?
5 A.Yes. Customers are billed throughout each
6 month and billing periods, or cycles, typically include
7 portions of more than one calendar month. Prior to the
8 05-28 Case, billing period data was converted into
9 calendar month data using a simple linear interpolation.
10 Daily consumption during the billing period was assumed
11 to be flat, and weather effects were ignored. The
12 aggregate calendar month data was then used in the
13
14
determination of the coincident peak demands for each
customer class.
15 Under the new "workshop methodology," billing
16 period data is now converted into calendar month data
17 using a nonlinear method based on load research data that
18 utilizes actual daily usage patterns. Total daily
19 consumption is assumed to fluctuate in proportion to the
20 fluctuations in the daily consumption of the load
21 research sample customers. This methodology captures the
22 effects of weather on energy consumption and improves the
23 process of determining coincident peak demand
2 4 responsibili ty.
25 Q.In the Company's 05-28 Case, two
490 TATUM, DI 10
Idaho Power Company
.
12.13
14
l5
16
17
18
19
20
21
22
23
24.25
1 cost-of-service studies were prepared, one using a
2 surrogate demand
3
4 /
5
6 /
7
8 /
9
10
11
491 TATUM, 01 10a
Idaho Power Company
.
.
.
1 normalization methodology and one using the traditional
2 methodology. Has the Company selected a preferred method
3 for determining the class coincident peak demands for use
4 in this case?
5 A.Yes. After evaluating the two approaches for
6 determining the class coincident peak demands, Idaho
7 Power's Load Research Department has recommended the
8 surrogate demand normalization methodology as the
9 preferred approach. This "normalized" approach serves to
10 mitigate the impact of unusual weather conditions that
11 may exist in a test year.
12 The surrogate demand normalization methodology
13 uses the five-year median demand ratios from the load
14 research sample applied to the normalized monthly energy
15 values for each customer class to determine the
16 coincident peak demands by class. This methodology
17 reduces the effect of any atypical demand ratios that
18 might exist in a given test year due to unusual weather
19 conditions.
20 PROPOSED MODIFICATIONS TO
THE SYSTEM COINCIDENT DEM METHODOLOGY
21
22 Are you proposing any other changes to theQ.
23 manner in which the coincident peak demands are
24 determined?
25 A. Yes. As part of this general rate case
proceeding, I am proposing an additional modification to
492 TATUM, DI 11
Idaho Power Company
.
.
.
1 the method used to derive the coincident peak demand
2 values in an attempt to better reflect the impact that
3 the Irrigation Peak Rewards program has on the Company's
4 peak demands.
5 Q.Please provide an overview of the structure and
6 purpose of the Irrigation Peak Rewards program.
7 A.The Irrigation Peak Rewards program is a demand
8 response program available to agricultural irrigation
9 customers with pumps of 75 horsepower and greater. The
10 program is designed to reduce peak demand by turning off
11 participating irrigation pumps during peak demand hours
12 during the irrigation season in exchange for a financial
13 incenti ve. Through this program, the Company has been
14 successful in reducing load during the summer afternoon
15 hours when costs to provide energy are typically higher.
16 Q.Please describe how the process used to derive
17 the class coincident peak demands has been modified to
18 better reflect the impact that the Irrigation Peak
19 Rewards program has on the Company's peak demands.
20 A.As described earlier in my testimony, the
21 Company's surrogate demand normalization methodology for
22 estimating system coincident demands utilizes five years
23 of load research sample data to derive monthly five-year
24
25
493 TATUM, DI 12
Idaho Power Company
.
.
.
1 median system coincident demand factors for each customer
2 class. A system coincident demand factor is the ratio of
3 the system coincident demand to the average demand. To
4 deri ve the monthly system coincident demands, the monthly
5 five-year median factors from each sample are applied to
6 the associated population's monthly average demands for
7 the test year.
8 This year, a modified procedure was developed
9 to incorporate the system coincident demand reductions
10 from the Irrigation Peak Rewards program into the system
11 coincident demands for the Irrigation class. To
12 accomplish this obj ecti ve, the Irrigation class's system
13 coincident demand factors for 2004-2007 were first
14 revised to reflect what the system coincident demands
15 would have been absent the Irrigation Peak Rewards
16 program by removing all of the program participants from
17 the irrigation load research sample. The remaining
18 nonparticipants in the sample were used to determine the
19 revised system coincident demand factors with no demand
20 reduction from the program. Since the program began in
21 2004, the system coincident demand factors for 2003 did
22 not need revision.
23 Next, the resulting "non-participant" system
24 coincident demand factors were adjusted to reflect the
25 full impact of the coincident demand reductions of the
494 TATUM, DI 13
Idaho Power Company
.
.
.
1 Irrigation Peak Rewards program. If the time of the
2 historical system peak was outside of the Peak Rewards
3 window of operation from 4 p.m. to 8 p.m., there was no
4 adj ustment to the system coincident demand factor. This
5 method is described in greater detail in my workpapers.
6 PROPOSED MODIFICATIONS TO
THE COMPANY'S COST-OF-SERVICE METHODOLOGY
7
8 Q.Please briefly describe each of the three
9 cost-of-service studies prepared as part of this general
10 rate case proceeding.
11 A.The three studies prepared as part of this
12 general rate case proceeding include a base case study
13 ("Base Case"), a modified base case study ("Modified Base
14 Case"), and a study identified as the "3CP/12CP" study.
15 The Base Case study applies a methodology similar to that
16 used in the preparation of the cost-of-service study in
17 the 03-13 Case, the last case in which the Commission
18 approved a study. The Modified Base Case study deviates
19 from the Base Case method in two ways:(1) PURPA and
20 purchased power expenses are classified as demand-and
21 energy-related in the same manner as steam and hydro
22 generation plant and (2) the energy-related cost
23 allocators, "EI0S" and "EI0NS," are derived using an
2 4 averaging approach. In addition to incorporating the
25 changes applied in the Modified Base
495 TATUM, DI 14
Idaho Power Company
.
.
.
1 Case, the 3CP /12CP study further modifies the Base Case
2 study by allocating the costs of the Company's generation
3 peaking facilities differently than its base-load
4 resources. I will describe each study in greater detail
5 later in my testimony.
6 Q.Other than the changes to the preparation of
7 the coincident peak demand values described earlier, does
8 the Base Case cost-of-service study apply the same
9 methodology used to prepare the cost-of-service study in
10 the 03-13 Case?
11 A.Yes. While the accounting data and other
12 inputs to the. model have been updated to align with the
13 2008 test year, the overall methodology, with the changes
14 I described earlier, is consistent with that applied in
15 the 03-13 Case.
16 Q.Have you incorporated any changes into the
17 cost-of-service methodology to better reflect the ways in
18 which costs are currently imposed on the Company's
19 system?
20 A.Yes. The two additional studies prepared as
21 part of this general rate case proceeding, the Modified
22 Base Case study and the 3CP /12CP study, incorporate a
23 number of changes to the Base Case cost-of-service
24 methodology in an effort to better reflect the ways in
25 which costs are currently imposed on the Company's
system.
496 TATUM, 01 15
Idaho Power Company
.
.
.
1 Q.How does the allocation approach used under the
2 Modified Base Case study differ from the methodology used
3 in the Base Case?
4 A.The Modified Base Case study differs from the
5 Base Case study in the manner in which PURPA and
6 purchased power expenses are classified as demand-and
7 energy-related. Under the Modified Base Case study,
8 PURPA and purchased power expenses booked to FERC Account
9 555 are classified as demand-and energy-related in the
10 same manner as steam and hydro generation plant. In
11 addition, the energy-related cost allocators, EI0S and
12 EI0NS, are derived by averaging the normalized energy
13 values for each customer class with the normalized energy
14 values weighted by the marginal energy costs.
15 On what basis has the Company historicallyQ.
16 classified PURPA and Purchased Power expenses booked to
17 FERC Account 555?
18 A.FERC Account 555 has historically been
19 classified as either demand-related or energy-related
20 according to an "as-billed basis." That is, purchased
21 power expenses are classified as either demand- or
22 energy-related based upon the structure of the power
23 purchase contract between the Company and the energy
24 seller. FERC Account 555 has two sub-accounts: 555.1,
25 Purchased Power
497 TATUM, DI 16
Idaho Power Company
.
.
.
1 (non-PURPA purchases), and 555.2, Cogeneration and Small
2 Power Production (PURPA purchases). Sub-account 555.1,
3 Purchased Power, has historically been classified as
4 "energy only" to align with the structure of the purchase
5 agreements. Sub-account 555.2, Cogeneration and Small
6 Power Production, has, in recent years, been classified
7 as approximately 95 percent energy and approximately 5
8 percent demand.
9 Q.How did the Company arrive at the 95 percent to
10 5 percent split between energy and demand for sub-account
11 555.2?
12 A.Prior to July 1983, each cogeneration and small
13 power production agreement contained both a capacity and
14 energy payment component. The Commission's Order No.
15 18190, issued July 21, 1983, directed the Company to
16 restructure its cogeneration and small power project
17 rates to include only an energy-based component. The
18 demand-related dollar value booked to Account 555.2
19 represents the sum of the fixed capacity payments agreed
20 to under the active contracts executed prior to the
21 issuance of Order No. 18190, with the remainder of
22 sub-account 555.2 being classified as energy.
23 Q.Why do you believe that it is appropriate to
24 classify a larger share of the Company's Purchased Power
25
498 TATUM, DI 17
Idaho Power Company
.
.
.
1 expenses booked to FERC Account 555 as demand-related?
2 A.The Company's purchased power expenses have
3 grown in recent years to represent a larger share of the
4 overall revenue requirement. This growth in purchased
5 power expenses has occurred as market purchases and PURPA
6 proj ects have become further integrated into the
7 Company's resource portfolio. For example, in 2007,
8 purchased power was the source approximately 28 percent
9 of the Company's system-wide energy sales. Wi th that in
10 mind, it seems reasonable to begin to classify a larger
11 portion of FERC Account 555 as demand-related.
12 Q.Why are you recommending to classify Purchased
13 Power expenses booked to FERC Account 555 as demand- and
14 energy-related in the same manner as steam and hydro
15 generation plant?
16 A.As I stated earlier, market purchases and PURPA
17 proj ects continue to represent an increasingly larger
18 share of the Company's resource portfolio. Under the
19 traditional approach of classifying these expenses as
20 energy only, customers who use a larger proportion of
21 energy with respect to their demand (higher load factors)
22 receive a greater allocation of these expenses than would
23 have occurred if a power plant had been constructed to
24 serve the same loads. For example, if the Company had
25
499 TATUM, DI 18
Idaho Power Company
.
.
.25
1 chosen to build and operate a power plant to serve the
2 same customer loads served by purchased power, the plant
3 would have been classified as both demand and energy.
4 With that said, it seems reasonable to classify these
5 expenses as demand- and energy-related in the same manner
6 as the Company's steam and hydro generation plant.
7 Q.How does the allocation approach used under the
8 3CP /12CP differ from the methodology used in prior rate
9 case proceedings?
10 A.The 3CP /12CP study builds upon the revised
11 classification methodology applied in the Modified Base
12 Case by allocating production plant costs based on the
13 nature of the load being served. Under this approach,
14 production plant costs associated with serving summer
15 peak load are allocated separately from costs associated
16 wi th serving the base and intermediate load. That is,
17 the costs associated with building and operating
18 combustion turbines, which are used primarily to serve
19 summer peak loads, have been allocated to customers
20 differently than the costs associated with the Company's
.21 other generation resources.
22 Q.On what basis has the Company historically
23 allocated its' fixed generation costs?
24 A.Historically, Idaho Power has allocated all
fixed generation costs based on the average of the twelve
500 TATUM, DI 19
Idaho Power Company
.
.
.
1 monthly coincident peaks weighted by the monthly marginal
2 generation cost. This historical approach has attempted
3 to incorporate a forward-looking component into the
4 current costs through the use of marginal cost weighting.
5 This method has been effective in allocating costs to
6 customer classes based on peak demand during the higher
7 cost months. However, there is potential to
8 disproportionately allocate fixed base and intermediate
9 generation costs that do not vary greatly between the
10 summer and non-summer seasons to the higher cost summer
11 months.
12 Q.Does the 3CP /12CP approach reduce the potential
13 to disproportionately allocate fixed base and
14 intermediate generation costs that do not vary greatly
15 between the summer and non-summer seasons to the higher
16 cost summer months?
17 A. Yes. The 3CP /12CP method allocates production
18 plant costs associated with serving base and intermediate
19 load using an average of 12 monthly coincident demands
20 (" 12CP"), without marginal cost weighting. Using an
21 un-weighted 12CP allocator is more appropriate in this
22 case given that fixed base and intermediate generation
23 costs do not vary greatly between the summer and
24 non-summer seasons. Furthermore, the 3CP/12CP study
25 allocates fixed generation costs associated with serving
peak load using an
501 TATUM, DI 20
Idaho Power Company
.
.
.
1 average of the three coincident peak demands (" 3CP")
2 occur ring in June, Jul y, and Augus t . Thi s method 0 f
3 allocation isolates the costs associated with peaking
4 resources and allocates those costs according to the load
5 that is causing the investment.
6 Q.How did you arrive at the two cost categories
7 of base/intermediate and peak used in the 3CP/12CP study?
8 A.The cost allocation method used in the 3CP/12CP
9 study is baseq on the concept that the costs associated
10 with each of the Company's generation resources can be
11 categorized according to the type of loads being served.
12 Utilities typically experience three distinct time-based
13 production costing periods that are driven by customer
14 loads. The costing periods are normally identified as
15 base, intermediate, and peak. The base period is
16 equivalent to a low load or off-peak time period where
17 loads are at the lowest, normally during the nighttime
18 hours. The intermediate time period represents the
19 shoulder hours which are driven by the mid-peak loads
20 that typically occur throughout the winter daytime and in
21 the early morning and late evening during the summer
22 months. The peak category is driven by the peak loads
23 that occur during summer afternoons and evenings. The
24 base and
25
502 TATUM, DI 21
Idaho Power Company
.
.
.
1 intermediate loads on Idaho Power's system are typically
2 served by than same generation resources. In recognition
3 of that fact, those two categories have been combined for
4 cost allocation purposes. The generation resources that
5 serve the peak loads, i. e., combustion turbines, are
6 normally only utilized for that single purpose.
7 Consistent with that concept, the costs associated with
8 peak-related resources have been segmented into a second
9 category for cost allocation purposes.
10 Q.Please explain how production plant costs have
11 been classified as serving base and intermediate load.
12 A.The production plant costs that have been
13 classified as serving base and intermediate load are
14 captured in Accounts 310-316, Steam Production, and
15 Accounts 330-336, Hydraulic Production. The costs
16 identified under the Steam Production category represent
17 the Company's investment in the coal-fired generation
18 facili ties. The costs identified under the Hydraulic
19 Production category represent the Company's investment in
20 its hydroelectric generation facilities.
21 Q.How does the Company utilize its steam and
22 hydro resources to serve both base and intermediate
23 loads?
24
25
A.Utilities typically utilize their generation
resources to serve customer loads by operating the
503 TATUM, Dr 22
Idaho Power Company
.
.
.
1 resources with the lowest operating cost first and as
2 demand grows more costly resources are then dispatched.
3 This is no different for Idaho Power. However, since
4 hydroelectric generation is such a significant portion of
5 the Company's resource stack, stream flow conditions as
6 well as economics can influence the proportionate share
7 of output provided by steam and hydro resources
8 throughout the year. Since hydroelectric output is
9 highly dependent upon stream flows, steam production is
10 ramped up or down according to the production capability
11 of the hydro. Therefore, throughout the year, hydro and
12 steam production plants are utilized at varying
13 proportions to serve base and intermediate loads
14 according to the production capabilities of the hydro
15 plants. However, the combined monthly output of these
16 two resource types does not vary significantly between
17 the summer and non-summer months as does the output of
18 the combustion turbines.
19 Q.How do you propose to identify the fixed
20 generation costs associated with serving the peak load?
21 A.Accounts 340-346, Other Production, contain the
22 Company's investment in gas-fueled production plant. The
23 production plant investment captured in Accounts 340-346
24 represents the Company's investment in the combustion
25 turbine generation facilities used to serve peak demands.
504 TATUM, DI 23
Idaho Power Company
.
.
1 Q. Have you attempted to identify any other
2 production plant used to serve summer peak demands that
3 is not booked to Accounts 340-34 6?
4 A.No. I have simply identified as peaking plant
5 the investment in combustion turbine generation resources
6 that were constructed specifically to meet the summer
7 peak loads.
8 Q.Are the cost allocation modifications proposed
9 in the 3CP /12CP cost-of-service study, as compared to the
10 Modified Base Case, focused solely on the allocation of
11 generation costs?
12 A.Yes. In recent years, the Company's system
13 peak has grown at a much faster pace than average demand,
14 a trend that is expected to continue into the future.
15 For example, a comparison of Figures 4-1 and 4-2 on pages
16 39 and 40 of the 2006 IRP (included in my workpapers)
17 will show, that by 2012, the Company expects an energy
18 deficiency in. July of approximately 150 aMW with a peak
19 hour deficiency of almost 600 MW in the same month. In
20 response to the changing system load profile, combustion
21 turbines have been added as a cost-effective means to
22 serve peak load. This shift in resource mix has caused
23 the Company to investigate alternative methods for
24 allocating generation costs.
lt 25
505 TATUM, DI 24
Idaho Power Company
.
.
1 Q.The Company's investment in transmission and
2 distribution facilities has also grown in recent years.
3 Is there a need to adjust the allocation method for those
4 functional categories?
5 A.No. The Company's historical approach to cost
6 allocation for transmission and distribution facilities
7 is an effective method for equitably assigning costs to
8 customer classes during periods of growth. Under the
9 historical allocation method, transmission and
10 distribution costs are properly segmented according to
11 the manner in which the costs are imposed on the system.
12 As a result, the cost responsibility of each class can be
13 effectively identified through a combination of direct
14 cost assignment and cost allocation based on the
15 appropriate demand- or customer-based factors.
16 Q.Have you prepared a table that describes how
17 the allocation approaches vary among the three
18 cost-of-service studies submitted as part of this
19 proceeding?
20
21
22
23
24.25
506 TATUM, 01 25
Idaho Power Company
1 A..Yes.The following table is an illustration of
2 the general similarities and differences between the
3 three studies:
4
5
6
7
Hydro and Steam
Production
8
Other Production
(Peaking Units)
Transmission Plant
9 Distribution Plant
10 Other Expenses
11 Fuel
12 Purchased Power.13
59.38% Energy &
40.62% Demand
Demand
Demand
Demand and Customer
Energy
Energy (e: 3% Demand)
Same as Base Case
Same as Base Case
Same as Base Case
Same as Base Case
Same as Base Case
59.38% Energy &
40.62% Demand
Same as Base Case
Same as Base Case
Same as Base Case
Same as Base Case
Same as Base Case
59.38% Energy &
40.62% Demand
Generation Demand14
15
Hydro and Steam
Production
16 Other Production
(Peaking Units)
17
Generation Energy
18
19
Transmission
20
21 Distribution
22
23 Q.
12CP with Marginal
Generation Cost
Weighting
12CP with Marginal
Generation Cost
Weighting
12 Months Energy with
Marginal Energy Cost
Weighting
12CP with Marginal
Transmission Cost
Weighting
1NCP I No. of
Customers I Dire
Ass' nment
Same as Base Case
Same as Base Case
12 Months Energy with
Marginal Energy Cost
Weighting (averaged wi
un-weighted values)
Same as Base Case
Same as Base Case
12CP without Marginal
Generation Cost
Weighting
3CP without Marginal
Generation Cost
Weighting
12 Months Energy with
Marginal Energy Cost
Weighting (averaged wi
un-weighted values)
Same as Base Case
Same as Base Case
D~ you plan to cover each of the three
24 cost-of-service studies in equal detail as part of your.25 testimony?
507 TATUM, 01 26
Idaho Power Company
.
.
.
16
17
18
19
20
1 A.No. Because all three studies are quite
2 similar in their overall structure, I will cover the Base
3 Case study in greater detail and simply describe how the
4 other studies differ from the Base Case.
5 BASE CASE COST-OF-SERVICE STUDY DESCRIPTION
6 Q.Please identify the exhibits that comprise the
7 Base Case cost-of-service study.
8 A.The Base Case cost-of-service study is
9 comprised of the following exhibits:
10 Exhibit Description
11 Exhibi t No. 53 Functionalization and
Classification of Costs12
13
Exhibit No.54
Exhibit No.55
Exhibit No.56
Exhibit No.57
Exhibit No.58
Exhibit No.59 Development of Weighted Demand
and Energy Allocators
Summary of Functionalized Costs
14
Allocation to Classes
15
Summary of Class Allocations
Revenue Requirement Summary
Class Cost-of-Service Unit Costs
Q.Please describe Exhibit No. 53.
A.Exhibit No. 53 contains 130 pages and consists
21 of 11 Cost Functionalization and Classification Tables.
22 The functionalization and classification of each
23 component of rate base, operating revenue, and expense
24 are treated in detail in these tables. The tables are
25 shown in
508 TATUM, DI 27
Idaho Power Company
.
.
.
16
1 the following sequence:
2 Table No.Description
3 1 Electric Plant in Service
4 2 Accumulated Provision for
Depreciation
5
3 Addi tions and Deletions to Rate
Base6
7 4 Operating Revenues
8 5 Operation and Maintenance Expenses
9 6 Depreciation and Amortization
Expense
10
7 Taxes Other Than Income Taxes
11
8 Regulatory Debits/Credits
12
9 Income Taxes
13
10 Development of Labor-RelatedAllocator14
15 11 Functionalization Allocators
Q. What is the significance of the column headed
17 "Allocator" on Exhibit No. 53?
18 A.This column identifies, by symbol, the basis
19 for each allocation. For example, for Accounts 310
20 through 316, Steam Production, shown at line 20 on page
21 1, the constant "PI-S" is used to allocate the total
22 investment in steam production plant to the production
23 function and to the demand and energy cost
24 classifications. The resultant functionalization of
25 costs may itself serve as a basis for
509 TATUM, DI 28
Idaho Power Company
.
.
.
1 subsequent allocations. This use is illustrated at line
2 115 on page 16 where the accumulated depreciation for
3 steam production plant is allocated according to the same
4 allocator "PI-S" used at line 20.
5 Q .Please describe the classification of plant
6 utilized in the Base Case cost-of-service study.
7 A.In the class cost-of-service study all steam
8 and hydro production plants have been classified on a
9 demand and energy basis using the methodology preferred
10 by the Commission in prior general rate proceedings. The
11 energy portion of the steam and hydro production
12 investment has been determined by use of the Idaho
13 jurisdictional load factor of 59.38 percent. The
14 computation of the Idaho jurisdictional load factor is
15 included in my workpapers. By application of the load
16 factor ratio to the steam and hydro production plant
17 investment, the energy-related portion is easily
18 determined. The balance of the steam and hydro
19 production plant investment is then classified as
20 demand-related. All other production and transmission
21 plants have been classified as demand-related.
22 Q.Would you describe how distribution plant has
23 been classified?
24
25
A.Distribution substation plant, Accounts 360,
361, and 362, has been classified as demand-related.
510 TATUM, DI 29
Idaho Power Company
.
.
.
1 Distribution plant Accounts 364, 365, 366, 367, and 368
2 were classified as either demand-related or
3 customer-related using the same fixed and variable ratio
4 computation method utilized in the Company's prior
5 general rate case proceedings. The fixed to variable
6 ratio has been updated according to a system capacity
7 utilization measurement based on a three-year average
8 (2005-2007) load duration curve that is detailed in my
9 workpapers.
10 Q.Would you please describe the functionalization
11 of general plant?
12 A.General plant was functionalized based on total
13 production, transmission, and distribution plant. As a
14 resul t, a portion of general plant was assigned to each
15 production, transmission, and distribution function based
16 on each function's proportion to the total.
17 Q.How was the accumulated provision for
18 depreciation functionalized?
19 A.The accumulated provision for depreciation was
20 functionalized using the resulting functionalization of
21 costs for the appropriate plant item. For example, the
22 accumulated depreciation for steam production plant shown
23 at line 115 on page 16 is functionalized based on the
24 functionalization of steam production plant in service at
25 line 20.
511 TATUM, DI 30
Idaho Power Company
.
.
.
1 Q.Please describe Table 3 of Exhibit No. 53.
2 A.Table 3 indicates the functionalization of all
3 other additions to and deductions from rate base.
4 Deductions from rate base include customer advances for
5 construction and accumulated deferred income taxes.
6 Customer advances have been functionalized based on the
7 distribution plant investment against which the advances
8 apply. Accumulated deferred taxes have been
9 functionalized based on total plant investment.
10 Addi tions to rate base consist of fuel inventory, which
11 has been functionalized based on energy production, and
12 materials and supplies, which have been functionalized
13 based on the appropriate plant function. Deferred
14 conservation expenses have been functionalized based on
15 the Idaho jurisdictional load factor resulting in 59.38
16 percent of the deferred expenses being functionalized to
17 energy production and the remainder being functionalized
18 to demand production.
19 Q.Please describe the functionalization of other
20 operating rev~nue shown on Table 4 of Exhibit No. 53.
21 A.Other operating revenue is functionalized based
22 on either the functionalization of the related rate base
23 item or, in the situation where a particular revenue item
24 may be identified with a specific service, the
25 functionalization of the specific service item.
512 TATUM, DI 31
Idaho Power Company
.
.
.
1 Q.Briefly describe the method by which operation
2 and maintenance expenses were functionalized.
3 A.The functionalization of operation and
4 maintenance expenses is detailed on Table 5 of Exhibit
5 No. 53.In general, the basis for the functionalization
6 may be readily interpreted from the exhibit, particularly
7 because, in most cases, the functionalization is the same
8 as that for the associated plant.
9 Q.How is supervision and engineering expense
10 treated throughout the allocation of operation and
11 maintenance expenses?
12 A.For each applicable expense account in each
13 functional group, the labor component is separately
14 functionalized in accordance with the detail provided on
15 Table 10 of Exhibit No. 53. Referring to pages 91
16 through 105 of Table 10, it can be seen that the total of
17 allocated labor in each functional group becomes the
18 basis for the functionalization of supervision and
19 engineering expense. For example, for Account 535 at line
20 675, the labor-related supervision and engineering
21 expense is functionalized based on lines 676-680 which
22 represent the cumulative labor as functionalized for
23 Accounts 536 through 540 shown on page 91 of Exhibit No.
24 53. In a similar fashion, the allocation of supervision
25 and engineering associated with hydraulic
513 TATUM, DI 32
Idaho Power Company
.
.
.
1 maintenance expense, Account 541, is based on the
2 composite labor expense for Accounts 542 through 545, as
3 expressed by lines 683-686. Total functionalized labor
4 expense serves the additional purpose of functionalizing
5 employee pensions and other labor-related taxes and
6 expenses. Table 10 details the development of all
7 labor-related functionalization factors used in this
8 study.
9 Q.Please describe the functionalization of
10 depreciation expense, taxes other than income, and income
11 taxes shown on Tables 6, 7, 8, and 9, respectively.
12 A.Depreciation expense is functionalized based on
13 the function of the associated plant. Taxes other than
14 income are also functionalized based on the function of
15 the source of the tax. Deferred income taxes are
16 functionalized based on plant investment. The
17 functionalization of federal and state income taxes is
18 based on the functionalization of total rate base and
19 expenses and is discussed in more detail in my testimony
20 regarding the allocation of costs to classes of
21 customers.
22
23
Q.Please describe Exhibit No. 54.
A.Exhibi t No. 54 summarizes in row format the
24 functionalized costs for each component of rate base and
25 expenses shown across the columns on Exhibit No. 53.
Q. Please describe Exhibit No. 55.
514 TATUM, DI 33
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 A.Exhibi t No. 55 details the allocation of the
2 summarized costs shown on Exhibit No. 54 to each customer
3 class, including the special contract customers. The
4 exhibi t also includes a summary of results showing the
5 actual rate of return earned for each customer class and
6 special contract customer. The exhibit includes the
7 following tables:
8 Table No'.Description
9 1 Plant in Service
2 Accumulated Reserve for
Depreciation
3 Amortization Reserve
4 Substation CIAC
5 Customer Advances for Construction
6 Accumulated Deferred Income Taxes
7 Acquisition Adjustment
8 Working Capital
9 Deferred Programs
10 Subsidiary Rate Base
11 Plant Held for Future Use
12 Other Revenues
13 Operation & Maintenance Expenses
14 Depreciation Expense
15 Amortization of Limited Term Plant
515 TATUM, DI 34
Idaho Power Company
.
.
.
1 Table No.
16
17
18
19
20
21
22
Description
2 Taxes Other Than Income
3 Regulatory Debits/Credits
4 Provisions for Deferred Income
Taxes
Investment Tax Credit Adjustment5
6 Construction Work In Progress
7 State Income Taxes
8 Federal Income Taxes
9 23 Allocation Factor Summary
10 Q. Briefly describe the manner in which you
11 allocated the summarized costs shown on Exhibit No. 54 to
12 each class of service as shown on Tables 1 through 22 of
13 Exhibi t No. 55.
14 A.The demand-related generation and transmission
15 costs have been allocated to customer classes based on a
16 methodology that incorporates both actual and
17 marginal-cost-weighted coincident peak demands. The
18 energy-related generation costs have been allocated to
19 customer classes based on a methodology that incorporates
20 both actual and marginal-cost-weighted normalized monthly
21 energy consumption.
22 Q.What is the reasoning for using marginal cost
23 weightings in the derivation of the demand- and
24
25
516 TATUM, DI 35
Idaho Power Company
.
.
.
1 energy-related allocation factors?
2 A.The use of marginal cost weighting strikes a
3 balance between backward-looking costs already incurred
4 and forward-looking costs to be incurred in the future.
5 This approach inj ects into the allocation process
6 recogni tion of the influence seasonal load profiles have
7 on cost causation.
8 Q.Please describe the methodology used to derive
9 the demand-related allocation factors used to allocate
10 generation costs in the Base Case study.
11 A.The demand-related factors used to allocate
12 generation costs were derived using the same methodology
13 as that used since the Company's 03-13 Case. First,
14 ratios based on the sum of the actual coincident peak
15 demands for both the summer and non-summer seasons were
16 calculated for each customer class. Second, weighted
17 coincident peak demand values were derived by multiplying
18 the actual monthly coincident peak demands by the monthly
19 marginal costs. Corresponding ratios for both the summer
20 and non-summer seasons were then calculated for each
21 customer class. Finally, the actual summer and
22 non-summer ratios were averaged with the weighted summer
23 and non-summer ratios to derive the demand-related
24 allocators DI0S and DI0NS, respectively. These factors
25 where used to allocate
517 TATUM, 01 36
Idaho Power Company
.
.
.
1 demand-related generation costs to the customer classes.
2 Q.Have the generation capacity marginal costs
3 used in the current study been updated since the
4 Company's previous study in Case No. IPC-E-07-08?
5 A.Yes.The generation capacity marginal costs
6 have been updated to reflect the costs associated with
7 the Danskin CTI Combustion Turbine which came on line in
8 2008. The generation capacity marginal cost was
9 seasonalized based on the monthly peak-hour generation
10 deficiencies which the Company expects to encounter
11 during the next five years of the planning period based
12 on the 90th percentile water and 70th percentile load
13 cri teria used for planning purposes. These deficiencies
14 are detailed on page 78 of the 2006 IRP Technical
15 Appendix. I have included a copy of this page in my
16 workpapers. During the first five years (2008 through
17 2012) of the remaining planning period covered by the
18 IRP, the months in which peak-hour deficits exist are
19 May, June, July, August, September, and December. The
20 relative sizes of the five-year average monthly
21 deficiencies were used to define the share of the annual
22 capaci ty cost assigned to each month.
23 Q.How were the demand-related transmission
24 marginal costs determined?
25
518 TATUM, DI 37
Idaho Power Company
.
.
.
1 A. The transmission marginal costs reflect the
2 costs associated both with the integration of new
3 resources into the system and with the planned system
4 expansions needed to maintain reliable service as the
5 Company's loads continue to grow, combined with the
6 Hemingway-Boardman Capacity Upgrade. The marginal costs
7 associated with the new resource integration were
8 seasonalized based on the same methodology used for
9 generation capacity; that is, the relative sizes of the
10 five-year average monthly peak-hour deficiencies
11 identified in the 2006 IRP were used to define the share
12 of the annual capacity cost assigned to each month. The
13 marginal costs associated with the planned system
14 expansions and Hemingway-Boardman Upgrade were
15 seasonalized based on the monthly share of the projected
16 peak-hour load growth. The total demand-related
17 transmission marginal costs for each month were then
18 derived by adding the monthly values for both categories
19 of transmission costs.
20 Q.What factor was used to allocate transmission
21 costs to the customer classes?
22 A.The allocation factor D13 was used to allocate
23 transmission costs to customer classes. This factor was
24 derived using the same methodology as that used in the
25 Company's previous general rate case. First, ratios
519 TATUM, DI 38
Idaho Power Company
.
.
1 based on the sum of the actual coincident peak demands
2 were calculated for each customer class. Second,
3 weighted coincident peak demand values were derived by
4 mul tiplying the actual monthly coincident peak demands by
5 the monthly transmission marginal costs. Corresponding
6 weighted ratios were then calculated for each customer
7 class. Finally, the actual ratios were averaged with the
8 weighted ratios to derive the non-seasonalized
9 transmission allocation factor D13.
10 Q.Please describe the methodology used to derive
11 the energy-related allocation factors.
12 A.The energy-related allocation factors, EI0S and
13 EI0NS, were derived through a two-step process. First,
14 summer and non-summer ratios based on each class's
15 proportionate share of the total normalized energy usage
16 for the test year were determined. Next, summer and
17 non-summer ratios based on the monthly normalized energy
18 usage for each customer class weighted by the monthly
19 marginal cost. were calculated. This is the same method
20 used to derive the EI0S and EI0NS allocators in Case No.
21 IPC-E-03-13.
22 Q.Have the generation energy marginal costs used
23 in the current study to derive the EI0S and EI0NS
24 allocation factors been updated since the Company's.25
520 TATUM, DI 39
Idaho Power Company
.
.
.
19
1 previous study in Case No. IPC-E-07-08?
2 A.Yes. Updated marginal energy costs were
3 calculated by quantifying the difference in net power
4 supply costs resulting from the addition of 50 megawatts
5 of load to all hours of the Company's base case system
6 simulation run for the five-year period 2008 through
7 2012.
8 Q.Have you included information regarding the
9 derivation of the Company's updated marginal costs with
10 your testimony?
11 A.Yes. I have included a copy of the Company's
12 2008 Marginal Cost Analysis in my workpapers.
13 Q. Have you prepared an exhibit that details the
14 deri vation of the weighted demand and energy allocation
15 factors?
16 A.Yes. Exhibit No. 59 details the derivation of
17 the allocation factors DI0S, DI0NS, 013, EI0S, and EI0NS
18 used in the Base Case study.
Q.Have the marginal costs been used to develop
20 the Company's revenue requirement?
21 A.No. The marginal costs have been used solely
22 for purposes of developing allocation factors and not for
23 purposes of developing the Company's revenue requirement.
24
25
521 TATUM, DI 40
Idaho Power Company
.
.
1 Q.What was the method by which you allocated
2 costs associated with distribution plant included on
3 Exhibi t No. 54 to each class of customers?
4 A.The capacity components of distribution plant,
5 both primary and secondary, were allocated by the
6 non-coincident group peak demands for each customer class
7 identified as demand allocation factors D20, D30, D50,
8 and D60. The customer components of distribution plant,
9 both primary and secondary, were allocated by the average
10 number of customers identified as customer allocation
11 factors C20, C30, C50 and C60.
12 Q.What was the method by which you allocated
13 costs associated with customer accounting and customer
14 assistance expenses?
15 A.The principal customer accounting expenses
16 which require allocation are meter reading expenses,
17 customer records and collections, and uncollectible
18 accounts. The meter reading and customer records and
19 collection expenses were allocated based upon a review of
20 actual practices of Idaho Power Company in reading meters
21 and preparing monthly bills. The allocation of
22 uncollectible amounts again was based upon a review of
23 actual Idaho Power Company data. Customer assistance
24 expenses were allocated based on the average number of.25
522 TATUM, DI 41
Idaho Power Company
.
.
.
1 customers in each class.
2 Q.Does Exhibit No. 55 include a listing of the
3 allocation factors used to allocate to classes the
4 various costs shown on Tables 1 through 22?
5 A.Yes. Table 23 of Exhibit No. 55 includes a
6 listing of each allocation factor.
7 Q.How did you allocate state and federal income
8 tax to each customer class and special contract customer
9 as shown on Tables 21 and 22 of Exhibit No. 55?
10 A.The state and federal income taxes for the
11 Idaho jurisdiction, provided by Ms. Schwendiman, were
12 allocated to each customer class and special contract
13 customer according to each class's allocated share of
14 rate base. The worksheets showing this allocation are
15 included in my workpapers.
16 Q.What method was used to functionalize the state
17 and federal income taxes as shown on Table 21 and Table
18 22 of Exhibit No. 55?
19 A.Once the state and federal income taxes were
20 allocated to each customer class, they were
21 functionalized based on the functionalization of total
22 rate base and expenses for each class. For example, the
23 total summer power supply production rate base amount of
24 $70,613,133 allocated to the residential class on Tables
25 1 through 10
523 TATUM, DI 42
Idaho Power Company
.
.
.
1 of Exhibit No. 55, and shown in summary form on page 1 of
2 Exhibi t No. 55 at line 9, represents 7.46 percent of the
3 total rate base amount of $946,232,900 allocated to the
4 residential class. The state and federal income taxes
5 allocated to the residential class (,$1,655, 018? and
6 $8,616,374, respectively) are multiplied by this same
7 percent to establish the summer power supply production
8 components of ,$123,507? and $643,001 shown on Table 21
9 and Table 22 of Exhibit No. 55. This same methodology is
10 used for all functional components and customer classes
11 shown on Tables 21 and 22.
12 Q.Please describe Exhibit No. 57.
13 A. Exhibit No. 57 is the revenue requirement
14 summary based on the results of the Base Case class
15 cost-of-service study. The section headed "Revenue
16 Requirement for Rate Design" details the sales revenue
17 required from each customer class and special contract
18 customer. The sales revenue required includes return on
19 rate base, total operating expenses, and incremental
20 taxes computed using the net-to-gross multiplier of 1.642
21 provided to me by Ms. Schwendiman.
22
23
Q.Please describe Exhibit No. 57.
A.Exhibi t No. 57 shows the unit cost for each
24 function for metered service schedules as determined
25
524 TATUM, DI 43
Idaho Power Company
.
.
.
1 through the Base Case class cost-of-service study. The
2 billing units shown in the column labeled "(8)" reflect
3 the billing demands, normalized billing energy, basic
4 load capacity, and number of billings.
5 MODIFIED BASE CASE COST-OF-SERVICE STUDY
6 Q.Ple~se describe how the model inputs under
7 Modified Base Case study scenario differ from those used
8 in the Base Case study.
9 A.As I mentioned earlier in my testimony, the
10 Modified Base Case scenario is identical to the Base Case
11 study with the exception that (1) PURPA and purchased
12 power expenses are classified as demand-and
13 energy-related in the same manner as steam and hydro
14 generation plant and (2) the energy-related cost
15 allocators, EI0S and EI0NS, are derived using an
16 averaging approach.
17 Q.What portion of PURPA and purchased power
18 expenses were classified as demand-related and what
19 portion were classified as energy-related under the
20 Modified Base Case?
21 A.Under the Modified Base Case, PURPA and
22 purchased power expenses were classified as 40.62 percent
23 demand-related and 59.38 percent energy-related, the same
24 ratio of demand to energy used in the classification of
25 hydro and steam generation plant.
525 TATUM, DI 44
Idaho Power Company
.
.
.
1 Q.In the Base Case study, the energy allocators
2 EI0S and EI0NS were derived using a two-step process
3 under which summer and non-summer ratios based on the
4 monthly normalized energy usage for each customer class
5 were weighted by the monthly marginal cost. How do the
6 EI0S and EI0NS energy allocators differ under the
7 Modified Base Case study?
8 A.In the Modified Base Case study, a third step
9 was added by which the un-weighted summer and non-summer
lO ratios were averaged with the summer and non-summer
11 ratios weighted by the monthly marginal cost to derive
12 the summer and non-summer energy-related allocation
13 factors EI0S and EI0NS, respectively.
14 Q. Have you prepared an exhibit that details the
15 derivation of the energy-related allocation factors EI0S
16 and EI0NS used in the Modified Base Case study?
17 A.Yes~ Exhibit No. 60 details the derivation of
18 the both the demand- and energy-related allocation
19 factors used in the Modified Base Case study, including
20 EI0S and EI0NS.
21 Q.What is your rationale for moving to the
22 "averaging approach" in the derivation of the EI0S and
23 EI0NS energy allocators?
24
25
526 TATUM, DI 45
Idaho Power Company
.
.
.
16
1 A.The "averaging approach" is consistent with the
2 methodology used in the derivation of the demand-related
3 allocation factors that receive marginal cost weighting.
4 That is, the DIGs, DI0NS, and D13 allocation factors used
5 in the Base Case and Modified Base Case are all derived
6 under the same averaging methodology. In the 05-28 Case
7 and the last general rate case proceeding, Case No.
8 IPC-E-07-08, the Company began applying the "averaging
9 approach" as a rate stability measure intended to
10 mitigate any extreme impacts that the marginal costs may
11 have on cost allocation. However, in this case, the
12 relati ve differences between the factors produced under
13 ei ther method are quite small and, therefore, have little
14 impact on the resulting cost allocation.
15 3CP/12CP Cost-Of-Service Study
Q.Have you prepared any exhibits that detail the
17 3CP /12CP cost-of-service study?
18 A.Yes. The 3CP /12CP cost-of-service study is
19 comprised of the following exhibits:
20
21
22
23
24
25
Exhibit Description
Exhibit No.62 Functionalization andClassificationofCosts
Exhibit No.63 Summary of Functionalized Costs
Exhibit No.64 Allocation to Classes
527 TATUM, DI 46
Idaho Power Company
.
.
1 Exhibit Description
Exhibit No.65 Summary of Class Allocations
Exhibit No.66 Revenue Requirement Summary
Exhibit No.67 Class Cost-of-Service Unit Costs
Exhibit No.68 Development of Demand and EnergyAllocators
2
3
4
5
6
7 Q.Please describe how 3CP/12CP study the model
8 inputs differ from those used in the Base Case study.
9 A.As I mentioned earlier in my testimony, the
10 3CP/12CP study deviates from the Base Case methodology in
11 the same manner as the Modified Base Case. In addition
12 the 3CP /12CP cost-of-service study applies a different
13 approach to allocating production plant costs.
14 Q. What are the demand-related allocation factors
15 for production plant used in the 3CP/12CP study?
16 A.The derivation of the demand and energy
17 allocators used in the 3CP /12CP scenario are shown on
18 Exhibi t No. 68. In order to avoid confusion among the
19 various factors used in the model, I have used the names
20 "DI0BS" and "DI0BNS" to describe the factors used to
21 allocate the production plant associated with serving the
22 base and intermediate loads. The name "DI0P" is used to
23 describe the allocation factor used to allocate the
2 4 production plant associated with serving the peak loads..25
528 TATUM, 01 47
Idaho Power Company
.
.
1 Q.How were the demand-related allocation factors
2 for the 3CP/12CP study derived?
3 A.As can be seen in Exhibit No. 68, the DI0BS and
4 DI0BNS represent the non-weighted average twelve
5 coincident peak demands for the summer and non-summer
6 seasons respectively. The allocator DI0P represents the
7 non-weighted average three coincident peak demands for
8 the summer months of June, July, and August. The
9 allocators for transmission plant and the energy
10 allocators are the same as those used in the Modified
11 Base Case study.
12 Q.Why did you choose to derive the DI0BS, DI0BNS,
13 and DI0P allocation factors with no marginal cost
14 weighting?
15 A.The segmentation of production plant costs into
16 base/intermediate and peak allows for a cost allocation
i 7 approach that recognizes the seasonality of the loads
18 associated with each category of investment. Therefore,
19 there is no need for marginal cost weighting because the
20 seasonal nature of the loads is reflected in the
21 allocation factors.
22 Q.How does this approach differ from that used
23 for the Base Case?
24.25
A.Under the Base Case approach, all production
plant costs, which include base, intermediate, and peak,
529 TATUM, DI 48
Idaho Power Company
.
.
1 are allocated using the same allocation factors, i. e. ,
2 DI0S and DI0NS. In the Base Case, the marginal cost
3 weighting is applied to provide a seasonal recognition to
4 cost causation similar to that automatically recognized
5 through the "3CP" studies.
6 COMPARISON OF THE STUDY RESULTS
7 Q.How do the results from the Modified Base Case
8 study compare with the results from the Base Case study?
9 A.The classification of PURPA and purchased power
10 expenses as demand- and energy-related in the same manner
11 as steam and hydro generation plant and the application
12 of the energy-related cost allocators derived under an
13 "averaging approach" result in a higher revenue
14 requirement for Residential Service and Irrigation
15 Service and a lower revenue requirement for all other
16 customer classes, including the special contract
17 customers, as' compared to the Base Case. The Summary of
18 Revenue Requirement for this scenario, which details the
19 revenue requirement for each customer class, is included
20 as Exhibit No. 61.
21 Q.How do the results from the 3CP /12CP study
22 compare to the results from the Base Case study?
23
24
. 25
530 TATUM, DI 49
Idaho Power Company
.
.
.
1 A.The results from the 3CP /12CP scenario are
2 shown on Exhibit No. 66. The results from the Base Case
3 study are shown on Exhibit No. 57. As can be seen from
4 comparing these two exhibits, the 3CP /12CP results
5 indicate a higher revenue requirement for Residential
6 Service, Small General Service, and Traffic Control
7 Lighting and a slightly lower revenue requirement for all
8 other service schedules and special contract service than
9 do the results of the Base Case.
10 Q.Are there any similarities in the results among
11 the three cost-of-service studies that you have performed
12 as part of this proceeding?
13 A. Yes. Although the absolute values are
14 different, the results from all three studies indicate
15 that the Large Power Service (Schedule 19), Irrigation
16 Service (Schedule 24), Traffic Control Lighting Service
17 (Schedule 42), and special contract (Micron, Simplot, and
18 DOE) customers should have an increase in rates which is
19 greater than the overall average increase requested by
20 the Company. In addition, the results indicate that
21 Dusk-to-Dawn Customer Lighting Service (Schedule 15),
22 Unmetered General Service (Schedule 40), and Street
23 Lighting Service (Schedule 41) should have a decrease in
24 rates from the current level. Exhibit No. 69 includes in
25 summary form the
531 TATUM, DI 50
Idaho Power Company
.
.
.25
1 resul ts from all three cost-of-service studies.
2 Q.After reviewing the results of each study, do
3 you have a preferred cost-of-service approach?
4 A.Yes. The 3CP /12CP study applies my preferred
5 approach.
6 Q.Why is the 3CP/12CP study your preferred
7 approach to cost allocation?
8 A.Of the three studies, the 3CP/12CP study
9 applies an approach that results in the most equitable
10 allocation of costs to customer classes. Each study was
11 prepared with the same goal of allocating costs to
12 customer classes according to the cost impact that each
13 class imposes on the utility system. However, the
14 3CP /12CP study applies a cost-of-service methodology that
15 best reflects the ways in which costs are currently
16 imposed on the Company's system. For example, over the
17 last six years, Idaho Power has added four combustion
18 turbine generation units to serve summer peak loads.
19 Because the costs associated with these new units are
20 driven primarily by summer loads, it is appropriate to
21 allocate the cost of those new resources according to
22 each class's contribution to the summer peak loads.
23 However, production plant costs associated with serving
24 the base and intermediate loads are driven more by the
monthly peaks throughout the entire
532 TATUM, DI 51
Idaho Power Company
.
.
.
1 year. By separating the production plant into the two
2 categories, the generation costs can be allocated
3 according to the most appropriate cost driver.
4 Q.Did you discuss all three studies internally
5 before deciding on your recommendation?
6 A.Yes. I arrived at my final recommendation
7 after discussing the results of each of the three studies
8 wi th Mr. Gale. Following that discussion, I provided the
9 class cost-of-service unit costs, detailed on Exhibit No.
10 67, to Ms. Waites, Ms. Nemnich, and Ms. Bowman for their
11 use in determining the component charges for each service
12 schedule.
13 REVENU REQUIRENT ALLOCATION
14 Q.What is the Company's general philosophy on
15 determining rates?
16 A.The Company's primary approach to ratemaking in
17 the last several general rate cases has been to establish
18 rates that reflect costs as accurately as possible.
19 Accordingly, the Company's ratemaking proposals usually
20 advocate movement towards cost-of-service results, which
21 assign costs to those customer classes that cause the
22 Company to incur the costs.
23 Q.Are there other obj ecti ves that may be
24 considered in the ratemaking process?
25
533 TATUM, DI 52
Idaho Power Company
.
.
.
14
1 A.Yes. The Commission may consider a number of
2 other obj ecti ves, such as rate stability, rate shock, and
3 abili ty to pay in the determination of rates.
4 Q.How did you approach the determination of the
5 revenue requirement for each customer class?
6 A.A pure cost-of-service revenue spread would
7 result in substantial increases to Irrigation Service,
8 Large Power Service, Traffic Control Lighting Service,
9 and to the three special contract customers. In order to
10 mi tigate the magnitude of the rate increase to each of
11 these customer classes that would be necessary to bring
12 them to current cost-of-service levels, the Company is
13 proposing to cap the percentage increase to those
customer classes at 15 percent or approximately one and
15 one-half times the average increase.
16 Q.Did you discuss the results of the
17 cost-of-service study internally before deciding to apply
18 the 15 percent caps to the specified customer classes?
19 A.Yes. I discussed the results of the
20 cost-of-service study and potential rate spread scenarios
21 with Mr. Gale, who is responsible for the overall
22 preparation of this case. My revenue allocation
23 recommendation is a result of those discussions.
24
25
534 TATUM, DI 53
Idaho Power Company
.
.
1 Q. Do you have an exhibit that details the class
2 revenue requirement determination?
3 A.Yes. Exhibit No. 70 is a four-page exhibit
4 that steps through the revenue requirement allocation
5 process from the cost-of-service results to the ultimate
6 proposal for each customer class. Page 1 of Exhibit No.
7 70 is the proformed normalized test year sales and
8 revenues. Page two details the results from the
9 cost-of-service study and illustrates the revenue changes
10 that would be made to each customer class to obtain the
11 cost-of-service results. Page three shows the revenue
12 shortfall that resulted by applying a 15 percent cap to
13 the specified customer classes. Finally, Page four shows
14 the proposed increase to the other customer classes which
15 resul ted from spreading the shortfall created by the
16 mi tigation to the remaining classes in order to obtain
17 the total Idaho jurisdictional target revenue
18 requirement. I have provided the results from Page four
19 to Ms. Waites, Ms. Nemnich, and Ms. Bowman for their use
20 in determining the individual rates for the Company's
21 general tariff and special contract customers.
22 FIXED COST ADJUSTMNT RATES
23 Q.Please describe the Fixed Cost Adjustment
24 ("FCA") mechanism.
lt 25
535 TATUM, DI 54
Idaho Power Company
.
.
.25
1 A.The FCA is a rate mechanism that is designed to
2 remove the financial disincentive to utility acquisition
3 of demand-side management resources. The mechanism
4 accomplishes this goal by severing the link between
5 energy sales and the recovery of fixed costs. Currently,
6 the FCA applies only to Residential Service (Schedules 1,
7 4, and 5) and Small General Service (Schedule 7). The
8 annual FCA amount is determined according to the
9 following formula:
10 FCA = (CUST X FCC) - (NORM X FCE)
11 Where:
12 FCA = Fixed Cost Adj ustment;
13 CUST = Actual number of customers, by class;
14 FCC = Fixed Cost per Customer, by class;
15 NORM = Weather-normalized energy, by class;
16 FCE. = Fixed Cost per Energy, by class.
17 Q.What values are required to calculate the FCA
18 amount annually?
19 A.As outlined in the above formula, for each
20 class (Residential Service and Small General Service),
21 the actual number of customers ("CUST"), the fixed cost
22 per customer ("FCC"), weather-normalized energy ("NORM"),
23 and the Fixed Cost per Energy ("FCE") are required to
24 determine the FCA amount. Two of these variables (CUST
and NORM) are determined at the end of each year based
upon the Company's
536 TATUM, DI 55
Idaho Power Company
.1 actual billing records. The other two variables (FCC and
2 FCE) are updated each time the Company files a general
3 rate case and are based on the results of the class
4 cost-of-service study.
5 Q.Have you updated the FCC and FCE rates as part
6 of this general rate case proceeding?
7 A.Yes. Pursuant to Order No. 30556, I have
8 updated the FCC and the FCE rates using the
9 functionalized revenue requirement data resulting from
10 the 3CP/12CP cost-of-service study included on Exhibit
11 No. 67. The updated FCC and FCE rates have been included
12 on the revised Schedule 54, Fixed Cost Adj ustment..13
14
Q. Please describe the process used to determine
the FCC and FeE rates for the FCA mechanism, which have
15 been submitted as part of this general rate case
16 proceeding.
17 A.The FCC and FCE rates submitted as part of this
18 general rate case proceeding are based upon the 2008 test
19 year. These rates most accurately represent the
20 Company's current fixed costs. Exhibit No. 71, Tables I,
21 II, and III detail the computational process that was
22 used to determine these class-specific fixed-cost
23 amounts.
24 The first step in this process is a.25 determination of the 2008 test year fixed cost recovery
embedded in the
537 TATUM, DI 56
Idaho Power Company
.
.
.
1 energy charges for Residential Service and Small General
2 Service customers. As can be seen on Exhibit No. 71,
3 Table III, column J, for Residential Service,
4 $179,439,869 of fixed costs is to be recovered from the
5 residential customers through energy charges. For Small
6 General Service, $9,661,329 of fixed costs is to be
7 recovered from the energy charges.
8 Q.Do these fixed cost amounts for the Residential
9 and Small General Service customer classes include more
10 than their actual class cost of service?
11 A.Yes.There is a difference between the class
12 cost of service numbers and the amount of requested
13 revenue requirement. This difference is a result of the
14 cross-class subsidies that are currently present in the
15 Company's rate structure. The total cross-class
16 subsidies as well as the fixed cost portion of those
17 subsidies are identified on Exhibit No. 71, Table II.
18 Q.Why is it important to include these fixed cost
19 subsidies for the Residential and Small General Service
20 classes?
21 A.When fixed costs are recovered through a
22 volumetric rate, the effects of any conservation program
23 that reduces energy consumption results in a loss in the
24 recovery of those fixed costs. In the case of both the
25
538 TATUM, DI 57
Idaho Power Company
.
.
.
14
1 Residential and Small General Service customer classes,
2 the reduction of energy consumption through conservation
3 measures not only prevents the Company from recovering
4 the fixed costs associated with those classes but, in
5 addi tion, prevents the fixed cost recovery of the
6 subsidies which are incorporated in their energy rates.
7 Q.How are the class-specific fixed cost amounts
8 established in the initial step used to derive the
9 updated FCC rates?
10 A.The determination of the FCC rate utilizes the
11 annual average number of customers for the Residential
12 customer class and Small General Service customer class.
13 As can be seen on Exhibit No. 71, Table III, column A,
the 2008 average number customers is 391,057 for the
15 Residential customer class and 31,196 for the Small
16 General Service customer class.
17 Wi th these two principal base level values, the
18 FCC rate can be determined. The annual fixed costs
19 recovered through the energy charges divided by the 2008
20 average number of customers results in an annual fixed
21 cost recovery per customer, or the FCC rate, shown on
22 Exhibit No. 71, Table III, column K. For the Residential
23 class, the annual fixed cost recovery per customer is
24 $458.86 ($179,439,869 I 391,057). For the Small General
25 Service
539 TATUM, DI 58
Idaho Power Company
.
.
.
14
1 class, the annual fixed cost recovery per customer is
2 $309.69 ($9,661,329 / 31,196).
3 Q.How are the class-specific fixed cost amounts
4 established in the initial step used to derive the
5 updated FCE values?
6 A.The determination of the FCE rate utilizes the
7 Residential and Small General Service weather-normalized
8 energy consumption for the 2008 test year included on
9 Exhibit No. 78. As can be seen on Exhibit No. 71, Table
10 III, column B, the 2008 weather-normalized annual energy
11 consumption for the Residential customer class is
12 5,065,086,947 kWh and annual energy consumption for the
13 Small General Service class is 190,586,226 kWh.
Wi th these additional principal base level
15 values, the FCE rate can be determined. The annual fixed
16 cost recovered through the energy charges divided by the
17 normalized energy results in an annual fixed cost
18 recovery per kWh, or the FCE rate, shown on Exhibit No.
19 71, Table III, column L. For the Residential class, the
20 fixed cost recovery per kWh is $0.035427 ($179,439,869
21 /5,065,086,947). For the Small General Service class,
22 the annual fixed cost recovery per kWh is $0.050693
23 ($9,661,329/190,586,226) .
24
25
540 TATUM, DI 59
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 Q.Is the methodology used to establish the FCC
2 and FCE rates in this general rate case proceeding the
3 same as that used the last time the FCC and FCE rates
4 were updated in Case No. IPC-E-08-04?
5 A.Yes. However, this is the first time that the
6 Company has submitted the revised FCA-related values as
7 part of a general rate case proceeding.
8 Q.Does this conclude your testimony?
9 A.Yes, it does.
541 TATUM, 01 60
Idaho Power Company
.
..
.
1 Q.Please state your name.
2 A.My name is Timothy E. Tatum.
3 Q.Are you the same Timothy E. Tatum that
4 previously presented direct testimony?
5 A.Yes, I am.
6 Q.Have you had the opportunity to review the
7 pre-filed direct testimony of Idaho Irrigation Pumpers
8 Association's witness Mr. Yankel; Micron Technology,
9 Inc. 's witness Dr. Peseau; Industrial Customers of Idaho
10 Power's witness Dr. Reading; and the U. S. Department of
11 Energy's witness Dr. Goins?
12 A.Yes, I have.
13 Q.What is the scope of your rebuttal testimony?
14 A.My testimony will focus on the issues raised by
15 the intervening parties regarding the Company's
16 cost-of-service study. It should be noted that any
17 omission on my part in addressing issues raised by the
18 parties does not indicate my concurrence with those
19 issues.
20 Q.What cost-of-service methodology does Mr.
21 Yankel recommend?
22 A.Mr. Yankel recommends an al ternati ve
23 cost-of-service methodology that introduces a "Growth
24 Corrected"
25
542 TATUM, DI REB 1
Idaho Power Company
.
.
.
1 component into the derivation of the allocation factors
2 for generation and transmission related costs.
3 Q.Do you agree with Mr. Yankel' s recommendation?
4 A.No. Mr. Yankel' s methodology does not
5 reasonably apportion costs among customer classes. Mr.
6 Yankel proposes to inject an additional growth-related
7 weighting factor into the existing weighted twelve
8 coincident peak demand method ("WI2CP"). His
9 growth-related weighting factors are based on the energy
10 sales growth forecast from the Company's Sales and Load
11 Forecast for the 2006 Integrated Resource Plan ("IRP").
12 This method results in an allocation of costs that is
13 predominately driven by forecasted energy sales growth
14 and fails to give adequate recognition to the impact that
15 existing loads have on costs.
16 Q.Is Mr. Yankel' s use of forecasted energy sales
17 growth to weight the class coincident peak demands
18 reasonable?
19 A.No. Mr. Yankel' s use of forecasted energy
20 sales growth to weight the class coincident peak demands
21 is not reasonable in either the derivation of the
22 weighting factors or in the manner in which the resulting
23 weighting factors are applied.
24
25
543 TATUM, DI REB 2
Idaho Power Company
.1 Q. What is the problem with the way in which Mr.
2 Yankel derives the "growth-adj usted" weighting factors to
3 be applied to the class coincident peak demands?
4 A.Mr. Yankel' s method incorrectly assumes that
5 energy sales by class will grow at the same or close to
6 the same rate as class coincident peak demands. This has
7 not been the case in recent history and is not expected
8 to be the case over the next several years.
9 Historically, peak demand has grown at a faster rate
10 than energy usage. Mr. Yankel illustrates this point
11 qui te well on page 10 of his direct testimony where he
12 presents the percentage change in annual system peak.13
14
demand and annual energy levels between the 1993 test
year and the 2008 test year. As can be seen on page 10
15 of Mr. Yankel' s testimony, the irrigation class's
16 contribution to the annual system peak grew by
17 approximately 6. 7 percent over the 15 year period while
18 the class's annual energy consumption declined by 4.4
19 percent.
20 Prospectively, Mr. Yankel' s assumption is also
21 incorrect according to the Company's 2006 IRP analysis,
22 which anticipates that system peak demands will grow at a
23 faster rate than average demands or energy sales.
.24
25
544 TATUM, DI REB 3
Idaho Power Company
.
.
.
1 Q. What is the problem with the way in which Mr.
2 Yankel applies the "growth-adjusted" weighting factors to
3 the class coincident peak demands?
4 A.Mr. Yankel' s growth adjustment places too great
5 an emphasis on the growth-related component of the
6 allocation factors. Under Mr. Yankel' s methodology, 50
7 percent of the allocation factors used to allocate
8 generation- and transmission-related costs is based
9 solely upon expected load growth. As a result, the
10 averaged allocation factors produced under this method
11 are based upon the invalid assumption that growth-related
12 costs represent 50 percent of the test year generation-
13 and transmission-related costs. Considering the
14 Company's generation- and transmission-related rate base
15 increased by only approximately 11 percent between the
16 2007 test year and the 2008 test year, the 50 percent
17 growth level assumed under Mr. Yankel' s methodology is
18 clearly inappropriate.
19 Q.Does Mr. Yankel' s growth-adj usted
20 cost-of-service study properly assign energy-related
21 costs to customer classes?
22 A.No, it does not. The degree at which Mr.
23 Yankel' s method fails to properly assign energy-related
24 costs is best illustrated on his Exhibit No. 301. As can
25 be seen on page 5 of Exhibit No. 301, Mr. Yankel derives
545 TATUM, DI REB 4
Idaho Power Company
.
.
.
1 an energy allocation factor ("EI0") that would assign
2 approximately 0.6 percent of the Company's energy-related
3 costs to the irrigation class; a class that represents
4 approximately 11.4 percent of the Company's annual energy
5 supplied. The EI0 allocation factor is used to allocate
6 variable costs such as fuel and a portion of purchased
7 power expenses that are tied directly to energy
8 consumption.It is not reasonable to suggest that,
9 because the irrigation class's energy consumption is not
10 growing, they should not be exposed to the rising
11 variable cost of energy.
12 Q.On page 21, lines 17-18 of Mr. Yankel's
13 testimony, he makes the following statement with regard
14 to his proposed methodology: "It does not attempt to
15 separate' old electrons' from 'new electrons' or 'new
16 customers' from 'old customers.'" Do you agree with Mr.
17 Yankel' s assessment of his proposal?
18 A.No. Mr. Yankel' s methodology does precisely
19 what he claims it does not. In fact, his proposed
20 growth-adj usted cost-of-service study has the effect of
21 turning back the clock by over 15 years with regard to
22 cost assignment for the irrigation class. This effect is
23 best seen by making a comparison similar to that made by
24 Mr. Yankel in his testimony. The Company's
25 cost-of-service
546 TATUM, DI REB 5
Idaho Power Company
.
.
.
1 study submitted as part of the 1993 general rate case
2 proceeding assigned the irrigation class a share of rate
3 base equal to $192,124,122. Mr. Yankel' s proposed
4 growth-adjusted cost-of-service study assigns to the
5 irrigation class a share of rate base equal to
6 $164,908,434. That is a 14 percent decrease in rate base
7 assignment (in nominal dollars) for the irrigation
8 customers even though, as Mr. Yankel points out on page
9 10 if his testimony, that class's coincident peak demand
10 has grown by 6. 7 percent over the same period. Mr.
11 Yankel' s results are counterintui ti ve.
12 Q.If the Commission determines that the
13 growth-related issues that Mr. Yankel identifies have
14 meri t, are there any adj ustments to his cost-of-service
15 methodology that could be made to produce more reasonable
16 results?
17 A Yes. Although Mr. Yankel' s method fails to
18 reasonably apportion costs among customer classes , it
19 could be modified to produce far more reasonable results.
20 This could be accomplished by changing the manner in
21 which the growth factors are derived and how they are
22 subsequently applied. As I pointed out earlier, energy
23 growth is not an appropriate basis for proj ecting growth
24 in demand. The Company forecasts capacity needs in its
25 IRP process. This
547 TATUM, DI REB 6
Idaho Power Company
.
.
.
1 process may provide the basis for a more reasonable
2 demand growth proj ection.
3 Assuming that a more reasonable demand growth
4 proj ection can be produced, another primary modification
5 that I would make to Mr. Yankel' s method relates to how
6 the growth adjustment would be applied. Under Mr.
7 Yankel' s proposed methodology, he applies marginal cost
8 weighting to only expected load growth, which corrupts
9 the resulting allocation factors. Instead, if the
10 marginal cost weighting was applied to existing loads
11 that were escalated to include the proj ected load growth,
12 the resulting allocation factors would include the growth
13 component Mr. Yankel advocates, while producing far more
14 reasonable results. For example, on page 1 of Mr.
15 Yankel' s Exhibit No. 301, residential load growth is
16 determined by applying 10.65 percent to the existing
17 monthly residential demands. The resulting values are
18 then weighted by the monthly marginal costs. This step
19 should be modified to instead escalate the residential
20 demands by 10~ 65 percent or by multiplying by 1.1065.
21 The resulting values would then be weighted by the
22 monthly marginal costs as the final step. This modified
23 approach would result in more reasonable cost assignment
24 than the method proposed by Mr. Yankel.
25
548 TATUM, DI REB 7
Idaho Power Company
.
.
.
1 Q.Mr. Yankel points out that his growth-adj usted
2 cost-of-service study does not address growth-related
3 costs on the distribution system. Has the Company taken
4 any steps to improve the manner in which it assigns costs
5 associated with growth on the distribution system?
6 A.Yes. On October 30, 2008, the Company filed
7 wi th the Commission a request to modify its line
8 installation and service attachment policy under Rule H
9 (Case No. IPC-E-08-22). The proposed modifications are
10 designed to place a larger share of the incremental
11 distribution system cost responsibility onto those
12 customers requesting new service. The Company views this
13 approach as an effective way to help alleviate the cost
14 impact that new customer growth has on existing
15 customers.
16 Q.Mr. Yankel proposes a second al ternati ve
17 cost-of-service study that is intended to reflect future
18 load reduction benefits of the Irrigation Peak Rewards
19 Program. Will you please describe your understanding of
20 Mr. Yankel' s second al ternati ve methodology?
21 A.As a second alternative, Mr. Yankel proposes a
22 cost-of-service methodology that reduces the coincident
23 peak demand responsibility of the irrigation customers by
24 50 percent to reflect, what Mr. Yankel estimates to be,
25 the
549 TATUM, DI REB 8
Idaho Power Company
.
.
.
13
14
1 load reduction potential of the proposed Irrigation Peak
2 Rewards program in 2009.
3 Q.Do you agree with Mr. Yankel' s cost-of-service
4 adj ustment to recognize estimated future benefits of the
5 Irrigation Peak Rewards Program?
6 A.No. I do not agree with Mr. Yankel' s
7 adjustment on a number of levels. First and foremost, I
8 do not believe that it is appropriate to make an
9 adj ustment to the test year loads based upon proj ected
10 future impacts of demand response programs. Secondly,
11 even if the Commission agrees with Mr. Yankel' s rationale
12 for the adj ustment, his load reduction proj ection is
based upon the operation of a program that has not yet
been approved by the Commission (Case No. IPC-E-08-23).
15 Furthermore, Mr. Yankel optimistically estimates the load
16 reduction potential of the Irrigation Peak Rewards
17 Program in 2009 to be 325 megawatts ("MW"). If the
18 Commission approves the proposed Irrigation Peak Rewards
19 Program as detailed in the settlement Stipulation, the
20 Company estimates the program will provide peak load
21 reduction of approximately 112 MW in 2009, much lower
22 than the 325 MW estimated by Mr. Yankel.
23 Q.Dr. Reading, Dr. Peseau, and Dr. Goins all
24 recommend that the Company depart from using the Idaho
25 jurisdictional load factor to classify hydro and steam
550 TATUM, DI REB 9
Idaho Power Company
.
.
.
1 production plant as demand and energy. Has the
2 Commission supported the use of the jurisdictional load
3 factor to classify steam and hydro production plant to
4 demand and energy in past rate case proceedings?
5 A.Yes. The Commission has supported the use of
6 the jurisdictional load factor to classify production
7 plant as demand and energy beginning with its Order No.
8 17856 issued in Case No. U-I006-185 in 1983. Following
9 Order No. 17856, the Company has used this method in all
10 cost-of-service studies filed with this Commission.
11 Q.Do you continue to support the use of the
12 jurisdictional load factor method of classifying
13 production plant as demand and energy?
14 A. Yes. The use of the system load factor to
15 classify production plant as demand and energy has been
16 and continues to be an appropriate method of
17 classification of steam and hydro production plant. This
18 method also aligns quite well with the 3CP /12Cp study,
19 the Company's preferred cost-of-service study. The use
20 of the jurisdictional load factor is based on the premise
21 that the need for hydro and steam generation plant is
22 driven both by customer demand and energy consumption.
23 The system load factor classification method provides a
24 means to identify the percentage of generation plant that
25 is needed to serve
551 TATUM, DI REB 10
Idaho Power Company
.
.
1 average demands (energy) and the percentage that serves
2 peak demands and classifies costs accordingly.
3 Q.What specific classification methodology does
4 Dr. Peseau recommend?
5 A.Dr. Peseau recommends a classification
6 methodology that assigns hydro production plant as 100
7 percent demand-related with 50 percent allocated as peak
8 and 50 percent as base load/intermediate load.
9 Furthermore, Dr. Peseau recommends classifying 100
10 percent of steam production plant as demand-related, all
11 being allocated as base load.
12 Q.Do you agree with Dr. Peseau' s classification
13 recommendation?
14 A. No.As I mentioned earlier in my testimony, a
15 portion of the need for the Company's hydro and steam
16 production plant capacity is driven by average demand or
17 energy. Dr. Peseau recommends a classification approach
18 that ignores this fact and assumes that the Company's
19 hydro and steam production capacity is driven entirely by
20 peak demand.
21 Q.What specific classification methodology does
22 Dr. Reading recommend?
23
24.25
552 TATUM, DI REB 11
Idaho Power Company
.
.
1 A.Dr. Reading recommends that hydro and steam
2 production plant be classified as 75 percent demand and
3 25 percent energy.
4 Q.Do you agree with Dr. Reading's classification
5 recommendation?
6 A.No. Dr. Reading supports his 75/25 demand to
7 energy approach for classifying hydro production plant
8 because it is the same approach used by PacifiCorp. Upon
9 further investigation, PacifiCorp adopted its 75/25
10 classification methodology through negotiations as part
11 of the Multi State Process, also referred to as Revised
12 Protocol. According to PacifiCorp' s ("Rocky Mountain
13 Power") cost-of-service witness C. Craig Paice1, the
14 75/25 classification methodology was accepted by
15 PacifiCorp because it" falls wi thin the middle range of
16 reasonable approaches."
1 7 Dr. Reading's justification for his classification
18 approach does not provide a sufficient basis for a change
19 of this magnitude. Idaho Power's classification method
20 should be based upon, at least in part, studies and
21 analyses using data specific to Idaho Power's system, not
22 PacifiCorp' s.
23
24 1 Utah Public Service Commission, Docket No. 07-035-93, Rebuttal
Testimony of C. Craig Paice, Page 4, Lines 87-88..25
553 TATUM, DI REB 12
Idaho Power Company
.
.
.
1 Q.What specific classification methodology does
2 Dr. Goins recommend?
3 A.Dr. Goins recommends that both hydro and steam
4 production plant be classified as 100 percent
5 demand-related. As an al ternati ve approach, Dr. Goins
6 recommends a classification scheme that classifies both
7 hydro and steam production plant as approximately 57
8 percent demand and 43 percent energy.
9 Q.What is your opinion of Dr. Goins's
10 classification recommendations?
11 A.I do not support Dr. Goins's 100 percent demand
12 classification approach for the same reasons I covered
13 earlier in my testimony with regard to Dr. Peseau' s
14 similar classification recommendation. However, Dr.
15 Goins's al ternati ve 57/43 classification method has some
16 appeal, as it has some relevance to Idaho Power's system.
17 It is my understanding that Dr. Goins's al ternati ve
l8 classification method is based on the ratio of the
19 weighted energy allocation factors in the "non-capacity
2 0 deficit months" to the deficit months. I am not
21 convinced that this method is superior to the Company's
22 historical load factor approach. However, should the
23 Commission wish to consider al ternati ve production plant
24 classification methodologies, Dr. Goins's 57/43
25 classification method is
554 TATUM, DI REB 13
Idaho Power Company
.
.
21
1 the most reasonable al ternati ve to the Company's
2 historical load factor approach presented in this general
3 rate case proceeding.
4 Q.Dr. Peseau points out on page 36 of his
5 testimony that the number of months in which the marginal
6 cost weighting factors are applied to the coincident peak
7 demands includes the months May and September. He argues
8 this results in "nonsensical" cost assignment. Has the
9 Company determined the number of months used to
10 seasonalize the coincident peak demands in a manner
11 different from the previously approved methodology?
12 A.No. In the 03-13 Case, the generation and
13 transmission marginal costs were seasonalized according
14 to the proj ected monthly peak hour capacity deficits
15 identified in the Company's most recent
16 Commission-acçepted IRP. In this case, the
17 Commission-accepted 2006 IRP was used in the same way.
18 The 2006 IRP analysis projects additional capacity
19 deficits in May and September which are reflected in the
20 weighting factors.
Q.Dr. Peseau argues that including the months of
22 May and September in the marginal cost analysis is
23 erroneous because those months have "typically been low
24 cost months" for Idaho Power's system. Is that a.25 legitimate critique of your approach?
555 TATUM, DI REB 14
Idaho Power Company
.
.
.
1 A.No. Whether or not May and September have been
2 "typically two of the lowest cost months" for Idaho
3 Power's system in the past is not relevant in this
4 instance. The inclusion of those months in the marginal
5 cost weighting factor process is consistent with the
6 approved methodology. I explained the reasoning for
7 using marginal cost weightings in the derivation of the
8 demand- and energy-related allocation factors on page 25
9 of my direct testimony:
10 The use of marginal cost weighting is intended
to strike a balance between backward-looking11 costs already incurred and forward-looking
costs to be incurred in the future.
12
13 The role of the seasonalized marginal cost weighting
14 approach is to provide the forward-looking aspect to the
15 allocation factors. While the historical seasonality of
l6 the costs imposed on Idaho Power's system is quite
17 important to consider in the overall assignment of costs,
18 it is not relevant in the context of a forward-looking
19 adjustment factor. According to the 2006 IRP, the
20 Company anticipates a need for additional generation and
21 transmission resources to successfully serve loads in May
22 and September prior to the end of 2012. As a result, the
23 marginal costs have been seasonalized in recognition of
24 this need to serve loads.
25
556 TATUM, DI REB 15
Idaho Power Company
.
.
1 Q.Dr. Peseau spends a considerable amount of time
2 in his testimony criticizing the Company's methodology
3 used to prepare its preferred cost-of-service study.
4 What cost-of-service methodology does Dr. Peseau
5 ultimately recommend?
6 A.Dr. Peseau accepts the Company's preferred
7 cost-of-service study, the 3CP /12CP Study, modified to
8 incorporate his classification approach discussed
9 earlier.
10 Q.What cost-of-service methodology does Dr.
11 Reading recommend?
12 A.Dr. Reading accepts the Company's preferred
13 cost-of-service study, the 3CP /12CP Study, modified to
14 incorporate his classification approach discussed earlier
15 as well as two additional adj ustments. His first
16 addi tional adj ustment relates to the manner in which the
17 coincident peak demands for each class are determined.
18 Dr. Reading proposes to use 2007 load research data to
19 compute the demand factors rather than applying the
20 surrogate for' a demand normalization methodology. Dr.
21 Reading's second adjustment is to use full marginal cost
22 weighting on the energy pllocation factors rather than an
23 average of weighted and unweighted factors as proposed by
24 the Company..25
557 TATUM, 01 REB 16
Idaho Power Company
.
.
1 Q. Do you agree with Dr. Reading's recommendation
2 to abandon the surrogate for a demand normalization
3 methodology?
4 A.No. The surrogate for a demand normalization
5 methodology was implemented in accordance with the
6 consensus of the parties involved in the cost-of-service
7 workshops conducted at the Commission's direction in Case
8 No. IPC-E-04-23 ("COS Workshop"). The surrogate for a
9 demand normalization methodology is one of two changes
10 that the Company agreed to as a result of the COS
11 Workshop process. Both changes were related to the
12 preparation of the coincident peak demands used to
13 compute the allocation factors for generation- and
14 transmission-related costs. The changes included (1) a
15 revised methodology to convert billing period data into
16 calendar month data and (2) a surrogate for a demand
17 normalization methodology.
18 Q.Were these two changes incorporated into the
19 cost-of-service studies prepared as part of Case No.
20 IPC-E-05-28 ("05-28 Case") and Case No. IPC-E-07-08
21 ("07-08 Case")?
22
23
24.25
A.Yes.
558 TATUM, DI REB 17
Idaho Power Company
.1 Q. Please explain why you favor the surrogate
2 demand normalization methodology used in this case as
3 opposed to methodology recommended by Dr. Reading.
4 A.Under the methodology recommended by Dr.
5 Reading, the coincident peak demands for each class would
6 be determined based upon demand ratios from the load
7 research data in a single year, 2007. The demand
8 normalization methodology used in this case uses the
9 fi ve-year median demand ratios from the load research
10 sample applied to the normalized monthly energy values
11 for each customer class to determine the coincident peak
12 demands by class. This methodology reduces the effect of.13
14
15
any atypical demand ratios that might exist in a given
test year due to unusual weather conditions.
Q.Do you agree with Dr. Reading's recommendation
16 to use full marginal cost weighting on the energy
17 allocation factors rather than an average of weighted and
18 unweighted factors as proposed by the Company?
19 A.No. My rationale for supporting the averaging
20 of weighted and unweighted factors in the derivation of
21 the energy allocation factors is detailed on page 46 of
22 my direct testimony:
23 The "averaging approach" is consistent with the
methodology used in the derivation of the24 demand-related.25
559 TATUM, DI REB 18
Idaho Power Company
.
.
1 allocation factors that receive marginal cost
weighting. That is, the DI0s, DI0NS, and 013
allocation factors used in the Base Case and
Modified Base Case are all derived under the
same averaging methodology. In the 05-28 Case
and the last general rate case proceeding, Case
No. IPC-E-07-08, the Company began applying the
"averaging approach" as a rate stability
measure intended to mitigate any extreme
impacts that the marginal costs may have on
cost allocation. However, in this case, therelati ve differences between the factors
produced under either method are quite small
and, therefore, have little impa.ct on the
resulting cost allocation.
2
3
4
5
6
7
8
9 Q.What cost-of-service methodology does Dr. Goins
10 recommend?
11 A.Dr. Goins recommends that the Company be
12 required to allocate costs according to a W12CP method
13 wi thout averaging the weighted and unweighted demand and
14 energy factors.
15 Q.Do you agree with Dr. Goins's recommendation
16 regarding the use of the W12CP cost-of-service
17 methodology?
18 A.No. Aside from the use of fully weighted
19 demand and energy allocation factors, the W12CP method
20 proposed by Dr. Goins is quite similar to the Company's
21 Base Case Study prepared in this proceeding. I discuss
22 on pages 20 and 21 of my direct testimony my rationale
23 for selecting the 3CP /12CP Study over the Base Case
24 Study. The
. 25
560 TATUM, DI REB 19
Idaho Power Company
.
.
.
1 3CP /12CP Study is a more effective method for aligning
2 cost causation with cost recovery by isolating the costs
3 associated with peaking resources and allocating those
4 costs according to the loads causing the investment.
5 The 3CP/12CP also reduces the potential that exists
6 under the W12CP method to disproportionately allocate
7 fixed base and intermediate generation costs that do not
8 vary greatly between the summer and non-summer seasons to
9 the higher cost summer months.
10 Q.In discussing his concerns with the Company's
11 preferred cost-of-service study, the 3CP/12CP method, Dr.
12 Goins's makes the following statement:
13 The study is seriously and probably fatally
flawed because it fails to align costsallocation with cost responsibility.14
15 Do you agree with Dr. Goins's assessment of the Company's
16 preferred cost-of-service study?
17 A.No. The study I have proposed uses a standard
18 ratemaking approach. The 3CP /12CP method incorporates an
19 allocation approach that is quite similar to the
20 Base-Intermediate-Peak ("BIP") method endorsed by the
21 National Association of Regulatory Utility Commissioners
22 ("NARUC") in its most current Electric Utility Cost
23 Allocation Manual dated January 1992. On page
24
25
561 TATUM, 01 REB 20
Idaho Power Company
.
.
1 60 of the NARUC manual, the BIP method is presented with
2 the following description:
3 The BIP method is a time-differentiated method
that assigns production plant costs to three
rating periods: (1) peak hours, (2) secondary
peak (intermediate, or shoulder hours) and (3)
base loading hours. This method is based on
the concept that specific utility systemgeneration resources can be assigned in the
cost of service analysis as serving different
components of load; i. e., base, intermediate,
and peak load components.
4
5
6
7
8
9 The Electric Utility Cost Allocation Manual
10 continues on page 61 with the following discussion of the
11 BIP method:
12 There are several methods that may be used for
allocating these categories of costs to
customer classes. One common allocation method
is as follows: (1) peak production plant costs
are allocated using an appropriate coincident
peak allocation factor; (2) intermediate
production plant costs are allocated using an
allocator based on the classes' contributions
to demand in the intermediate or shoulder
period; and (3) base load production plant
costs are allocated using the classes' average
demands for the base or off-peak rating period.
13
14
15
16
17
18
19 The NARUC BIP method has been around for many years and
20 incorporates much of the same cost of service logic and
21 theory that I applied in the 3CP /12CP method.
22
23
24
lt 25
562 TATUM, 01 REB 21
Idaho Power Company
.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1 Q.Does this conclude your direct rebuttal
Yes, it does.
2 testimony?
3 A.
4
5
6
7
8
9
563 TATUM, DI REB 22
Idaho Power Company
.
.
1 (The following proceedings were had in
2 open hearing.)
3 MR. WALKER: The witness is available for
4 cross-examination
5 COMMISSIONER SMITH: Mr. Ward.
6 MR. WARD: Thank you, Madam Chair.
7
8 CROSS-EXAMINATION
9
10 BY MR. WARD:
11 Q Mr. Tatum, I assume that you have read the
12 testimony of the other cost of service witnesses in this
13 case?
14 A I have.
15 Q And would you agree with me that there's
16 an underlying theme to the three cost of service experts
17 who are testifying on behalf of the high load factor or
18 contract customers and that is, if I may paraphrase it,
19 that since the last litigated case in 2003, there's been
20 a dramatic shift of costs to high load factor customers?
21 Would you agree with that, A, first of all, that there
22 has been such a shift and, B, that that's one of the
23 themes, common themes, of their testimony?
24.25
A Yes, I agree that those witnesses have
chosen to focus on that particular topic.
CSB REPORTING
[phone]
564 TATUM (X)
Idaho Power Company
.
.
.
1 Q And would it also be correct in a general
2 way that each of them find this shift to be difficult to
3 explain given the fact that, as you note in your rebuttal
4 testimony, peak consumption has been increasing faster
5 than energy consumption?
6 A Yes, they did attempt and struggled to
7 explain that occurrence, yes.
8 Q Okay. Now, also would you agree with me
9 that, in general, anything that happens in the cost of
10 service study that diminishes seasonality or
11 seasonalization of costs is going to tend to shift costs
12 to high load factor customers?
13 A No, not necessarily.
14 Q Well, let me ask about a more concrete
15 example, then. For instance, one of the changes that has
16 been made recently to cost of service is a shift to a
l7 fi ve-year average of costs rather than a single point or
18 single year's cost; correct?
19 A Well, just to clarify, I think you're
20 talking about the derivation of the allocation factors
21 for demand-related production and transmission costs; is
22 that correct?
23
24
25
Q Right.
A Yes, the methodology that derived those
allocation factors does incorporate the use of five years
CSB REPORTING
[phone]
565 TATUM (X)
Idaho Power Company
.
.
20
21
1 of data and taking the median value over that five-year
2 period for each month.
3 Q And I believe you explain that one of the
4 intents of that change is to eliminate possibly anomalous
5 resul ts in a single year.
6 A Yes.
7 Q Isn't it also true, though, that if over a
8 five-year time frame one class is growing more rapidly
9 than others or its peak load is growing more rapidly than
10 its energy consumption that that will have an impact on
11 cost of service results?
12 A The scenario that you described can impact
13 cost of service results. I don't know that it
14 necessarily has to impact the derivation of those factors
15 that we talked about a minute ago.
16 Q Well, let's assume for the moment that the
17 outsize growth of peak load as compared to energy
18 consumption is due primarily to growth in the residential
19 class, can you follow that assumption for a moment?
A Yes.
Q And if that growth has been occurring
22 steadily over. the last five years, isn't ita fact that
23 if we start using average allocators, we are going to
24 understate the residential class's responsibility for.25 that peak load growth?
CSB REPORTING
[phone]
566 TATUM (X)
Idaho Power Company
.
.
1 A Are we talking about average allocators or
2 median, the use of the median?
3 Q It wouldn't make any difference, either
4 average or median. If it's over five years and there's
5 been steady growth, if you take the average or the
6 median, you're going to understate the actual cost
7 responsibili ty that would exist as of the test year;
8 isn't that true?
9 A If that growth was linear, then I would
10 agree with that. If it's not and it's volatile and moves
11 up and down in each year, then I would say that that's
12 not necessarily true, that the median approach would
13 track trends over time.
14 Q But you don't select, in this five-year
15 analysis you don't select, the median year, you in fact
16 take an average; correct?
17 A Well, I guess it just depends on what
18 portion of the derivation of the allocation factors that
19 we're talking about. If you're talking about using an
20 average of coincident peak demands to weighted, you know,
21 the average of unweighted coincident peak demands and
22 weighted coincident peak demands weighted by marginal
23 cost, that's completely different than what we started
24 talking about a minute ago..25 Q I understand that and that's not what I'm
CSB REPORTING
[phone]
567 TATUM (X)
Idaho Power Company
.
.
.
1 asking about. What I'm asking about is in any case,
2 let's get away from cost of service for a moment, in any
3 case where you have growth, if you in fact are trying to
4 determine who -- what the situation is at the end of that
5 period of growth, if you attempt to average the last five
6 years, you're going to understate the impact of that
7 growth, are you not?
8 A Yes, you would, but that is not what we
9 did in this case.
10 Q All right, tell me what you did in this
11 case with the allocation factors.
12 A Well, we derived those allocation -- as I
13 mentioned earlier, we used for those customer classes
14 that we don't have actual hourly data, hourly load data,
15 for, we use a sample, we use sampling techniques to
16 determine the coincident peak, the coincident peak
17 demands for each customer class based on that sample.
18 The coincident peak demand values are derived by applying
19 a factor to the normalized energy in the test year.
20 Those factors are where we come into this use of a
21 median, so we look at factors that were derived from load
22 research samples over a five-year period and for each
23 month, for each class, we look at the factor and over the
24 fi ve-year period for each month, the median factor is
25 selected to derive the coincident peak demand for that
CSB REPORTING
[phone]
568 TATUM (X)
Idaho Power Company
.
.
.
1 customer class for that month, and so we're selecting the
2 median, the middle factor value over that five-year
3 period for each month for each customer class.
4 Q And doesn't that necessarily have to
5 understate if that growth is in fact linear or if it's
6 continuing, if you want to put it that way, doesn't that
7 have to understate the extraordinarily rapidly growing
8 class's cost responsibility?
9 A If the growth is linear over the five-year
10 period and we're using a median, then, yes, there would
11 be a lag, a two-year lag to be exact. You'd select the
12 middle year, in this case 2005. That didn't occur in
13 this case, but under your assumption, that is true.
14 Q All right, if you'd go to page 26 of your
15 testimony, direct testimony.
16 A Okay, I'm there.
17 Q And here you have a summary of the basic,
18 the three basic, approaches you've used in your cost of
19 service study; correct?
20
21
A Yes.
Q And what I'm interested in right at the
22 moment is the fact that in the modified base case, if you
23 look at the allocation methods and the modified base
24 case, you have used an averaging of marginal energy cost
25 weighting with unweighted energy costs; correct?
CSB REPORTING
[phone]
569 TATUM (X)
Idaho Power Company
.
.
18
19
1 A Correct.
2 Q And that's a change from the 2003 rate
3 case, is it not?
4 A It is.
5 Q And what's interesting about that is
6 wouldn't you normally make that change if in fact you
7 believed that system load factor is improving rather than
8 deteriorating?
9 A Actually, the change was made to, in order
10 to not place as much emphasis on the marginal cost
11 weighting for the energy allocation factors.
12 Q Let me ask it this way: Won't that
13 isn't it true that that change will be detrimental to the
14 high load factor customers?
15 A Detrimental, I assume you're meaning
16 detrimental in terms of cost allocation to the high load
17 class of customers.
Q Yes.
A In this case because of the results of the
20 marginal cost' study, it would result in more costs being
21 allocated -- energy-related costs being allocated or it
22 creates a portion of the costs to a greater extent to the
23 larger load factor customers, yes.
24.25
Q Now, that change in itself isn't enough to
explain the considerable difference in high load factor
CSB REPORTING
[phone]
570 TATUM (X)
Idaho Power Company
.
.
.
18
1 customer cost of service results that we see from 2003 to
2 this case, would you agree with that?
3 A Yes.
4 MR. WARD: Okay, now, I'd like to, if I
5 may, approach the witness, pass out a couple of exhibits.
6 COMMISSIONER SMITH: You may.
7 (Mr. Ward distributing documents.)
8 MR. WARD: I'm going to change the number
9 on this one to reflect that it's ours.
10 COMMISSIONER SMITH: Is that Exhibit 708?
11 MR. WARD: Commissioner, you are correct,
12 our next exhibit number would be 708 and I'd like
13 Mr. Said's Exhibit No. 50 remarked for identification as
14 708.
15 COMMISSIONER SMITH: Okay, could we just
16 go at ease for a minute?
17 (Pause in proceedings.)
19 Exhibit 708.
COMMISSIONER SMITH: We'll mark this as
20 (Micron Exhibit No. 708 was marked for
21 identification. )
22 MR. WARD: And then the document that's
23 identical at this point to Exhibit No. 134 I would like
24 identified as 709.
25 COMMISSIONER SMITH: Okay; so
CSB REPORTING
[phone]
571 TATUM (X)
Idaho Power Company
.
.
.
1 identified.
2 (Micron Exhibit No. 709 was marked for
3 identification. )
4 MR. WARD: Can we go at ease for a minute?
5 COMMISSIONER SMITH: Yes.
6 (Pause in proceedings.)
7 COMMISSIONER SMITH: All right, please
8 proceed, Mr. Ward.
9 MR. WARD: Thank you, Madam Chair. Now, I
10 think I've succeeded in causing everyone to lose their
11 place, including me.
12 Q BY MR. WARD: Now, Mr. Tatum, in earlier
13 examination I asked Mr. Said some questions about what's
l4 now 708. Do you recall that? Were you in the room when
15 that examination took place?
16 A Yes, a portion of the time anyway.
17 Q Okay. Well, if you have any questions
18 about it, please stop me and we can explain. Now, the
19 reason I have passed out Mr. Said's exhibit, Exhibit 708,
20 is that there" s no really comparable document in your
21 exhibi ts notwithstanding the fact that both of you used
22 for somewhat different purposes the AURORA model and you
23 in fact use the AURORA model in your cost of service
24 study, do you. not?
25 A I use the outputs from the AURORA model,
CSB REPORTING
[phone]
572 TATUM (X)
Idaho Power Company
.
.
.
1 yes.
2 Q Fair enough. Now, you use it for or in a
3 somewhat similar way as Mr. Said's use; that is, as I
4 understand it, in an attempt to determine marginal costs
5 for cost of service purposes, you again have the basic
6 inputs to the model and then you hypothesize a 50
7 megawatt addition; correct?
8 A Correct.
9 Q And the model, of course, makes a
10 determination just as it did for Mr. Said in Exhibit 708
11 of the marginal costs for each month in any particular
12 year you want to look at; correct?
13 A Yes,in my case using the average of the
14 '08 through 2012.
15 Q Okay. Now, and your numbers if we look at
16 your exhibits, your actual marginal cost numbers wiii be
17 somewhat different because you're using different bases,
18 correct, than Mr. Said?
19 A Actually, I'm using the exact same output,
20 but then the values that I have also include marginal
21 variable O&M as well, just slightly different.
22
23
Q Okay.
A But based on actually the same run with
24 the same inputs.
25 Q All right. Now, what I want to ask about
CSB REPORTING
[phone]
573 TATUM (X)
Idaho Power Company
.
.
.25
1 is, first of all, if you look at the very first line of
2 that exhibit, I calculated out from the annual total that
3 appears on the right that the average monthly energy
4 consumption would be 1,229,000 megawatt-hours. Does that
5 look about right to you? And you can certainly check it
6 if you want.
7 A So you are in the portion where we're
8 stating the energy values?
9 Q Correct.
10 A Up above, the top box?
11 Q That's right. Where you see under annual,
12 the number 14,750,000
13 A Yes.
Q --I just divided that by 12.
A Okay.
Q And I did the same thing for the cost.If
you look at the very next series of columns on the
14
15
16
17
18 right-hand side appears the number 88 point it's
19 millions actually, 88,421,000. Do you see that?
20 A Yes.
21 Q And I divided that by 12 and got 7,368,000
22 Now, the first thing I want to ask you about is, as we
23 know, this contains a depiction of the month by month, in
24 the top portion month by month, annual consumption I
mean month by month energy consumption and costs. Is
CSB REPORTING
[phone]
574 TATUM (X)
Idaho Power Company
.
.
20
1 that your understanding, net power supply costs?
2 A Yes.
3 Q And then finally down at the end at the
4 bottom we have under the heading Marginal Cost of Energy,
5 we have a marginal cost of energy determined by month.
6 Now, as I understand it, for your marginal weighting, you
7 used the months of June through August, which is
8 certainly understandable, but also May, September and
9 December; is that correct?
10 A I think we're moving from energy marginal
11 cost to capacity marginal cost?
12 Q Yes.
13 A Okay; so the exhibit that you're speaking
14 about right now is related to energy.
15 Q I understand that.
16 A And for energy, we used all months. We
17 have weightings for all months.
18 Q I understand.
19 A January through December.
Q But for capacity you used the six months I
21 just stated; isn't that right?
22 A For generation capacity, May, June, July,
23 August, September, December.
24.25
Q Okay. Now, I understand that we're
looking at energy here, not capacity and in fact, as to
CSB REPORTING
[phone]
575 TATUM (X)
Idaho Power Company
.
.
.
1 capaci ty or demand, Dr. Peseau' s testimony has some
2 charts, but what I'm interested in here is why does it
3 make any sense whether you're doing a capacity allocation
4 or energy to use, for instance, the month of May which is
5 less than normal or average monthly energy consumption
6 and considerably less in terms of net power supply
7 costs?
8 A So your question, then, just so I
9 understand, is about why we would use marginal cost
10 weighting in May for capacity, marginal capacity, costs,
11 is that your question?
12 Q That's correct.
13 A Okay. Well, the capacity costs are
14 seasonalized based on the monthly peak hour deficits that
15 are -- that come from our 2006 IRP and so that study
16 shows that we will have deficits in May and we want to
17 recognize that through this marginal cost analysis by
18 weighting May according to the magnitude of the deficits
19 identified in the IRP.
20 Q I understand that and were you here when
21 Mr. Said testified, in essence, let me get his quote just
22 right, that we should determine whether modeling results
23 square with historical results and if they -- now I am
24 going to paraphrase because that's all I could write down
25 quickly, and if in fact the modeling results appear
CSB REPORTING
[phone]
576 TATUM (X)
Idaho Power Company
.
.
.25
1 unrealistic or counterintui ti ve, then we should correct
2 the model, that's essentially how he testified earlier
3 today, isn't it?
4 A I think that's a fair characterization.
5 Q And here's what puzzles me, Mr. Tatum:
6 You said in your rebuttal testimony in defending the use
7 of May and/or September, which are both shoulder months,
8 that it's because we, of course, look to the IRP in an
9 attempt to give some forward-looking aspect to the cost
10 of service. Am I paraphrasing you correctly?
11 A I think the forward-looking language
12 appears in my direct testimony.
13 Q Okay, and I understand why you would want
14 to have a forward-looking view of costs; that is, if you
15 could discern trends that were changing, you would want
16 to reflect that in cost of service; right?
17 A I think we're trying to allocate current
18 costs based on current loads and current system
19 characteristics.
20 Q I would certainly agree with that and what
21 we're trying to do specifically when we're allocating
22 capaci ty costs is determine when peak loads occur and
23 allocate costs to those periods so that the appropriate
24 customers, i. e., those who are consuming at those peak
periods, pay the appropriate share of costs; correct?
CSB REPORTING
[phone]
577 TATUM (X)
Idaho Power Company
.
.
.
1 A I agree.
2 Q Under what scenario looking at May and
3 disregarding for the moment a 2006 IRP that may show a
4 capaci ty deficit, under what scenario can we possibly
5 believe that May is a peak cost month or will become at
6 any time in the future?
7 A Well, I'm relying on the accuracy of the
8 IRP analysis for the basis of the analysis or for the
9 basis of this analysis or at least that component and
10 that study identifies peak hour deficits which will
11 require capacity additions and we would like to reflect
12 that.
13 Q i understand that, but an IRP is an
14 operational document, is it not? It's a planning
15 document for when you're going to add resources or, for
16 that matter, when you will be adding load, any number of
17 things. It's operational, though, isn't it?
18 A It becomes the -- it's the plan for our
19 capacity additions into the future.
20 Q And is it possible or even likely that one
21 encounters an occasional need to add capacity to a
22 shoulder month because that's when your costs are lowest
23 and that's also when you do your maintenance and take
24 other outages, economic outages, for instance? That can
25 happen, can't it?
CSB REPORTING
[phone]
578 TATUM (X)
Idaho Power Company
.
.
.
1 A That scenario you just described can
2 happen to create a need for additional capacity. The
3 fact of the matter is that the IRP identified a need for
4 capaci ty and that's why we're recognizing that.
5 Q I understand why you did it, but that
6 practical planning need or engineering need doesn't
7 necessarily reflect financial costs, does it?
8 A Well, I certainly have to assume that the
9 assumptions going into the IRP that would identify those
10 defici t months or the peak hour deficits in those months
11 that they're taking into consideration the downtime for a
12 resource would be done at a time where it would provide
13 the lowest economic impact.
14 Q Okay, let me try to ask the question
15 another way. In a cost of service study, when we
16 identify peak periods, and it doesn't matter for the
17 moment what kind of cost of service study we're using, a
18 3CP, a 12CP, whatever, our attempt there is to identify
19 those periods in which maximum demands and, hence,
20 maximum costs within whatever framework we're using are
21 being placed on the system; isn't that true?
22 A The use of the weighting in those factors
23 is to identify those times when the Company would be
24 exposed to marginal capacity costs. I think that answers
25 your question. If it doesn't, please ask again.
CSB REPORTING
[phone]
579 TATUM (X)
Idaho Power Company
.
.
.
1 Q Well, marginal costs -- let me try one
2 more time. Marginal costs are of interest to us in a
3 cost of service study only insofar as the base historical
4 embedded cost record may not be sufficiently accurate as
5 to costs going forward; isn't that correct? I mean, what
6 we really care about is the embedded costs. That's what
7 we're allocating, isn't it?
8 A Correct.
9 Q And so if we can improve our embedded cost
10 study a little by using marginal costs or by taking
11 marginal costs into account, that makes some sense, but
12 isn't it also true that the marginal cost should never
13 turn the embedded cost world upside down?
14 A I guess I don't know what that means,
15 really, turning it upside down. I don't know what that
16 means.
17 Q Well, again, in embedded cost terms, we
18 can look at this document and at least as to energy say
19 May is not a high cost month. Can't we make that
20 determination right here?
21
22
23
A In terms of energy?
Q Yeah.
A Yes, in comparison to the other months,
24 the energy marginal cost is relatively low.
25 Q And so what sense does it make to price
CSB REPORTING
[phone]
580 TATUM (X)
Idaho Power Company
.
.
.
1 capaci ty as if May is a high cost month?
2 A Because those two things are independent
3 of one another.
4 Q Well, one more question and then I'll stop
5 belaboring this particular point. If I am a high load
6 factor customer and let's say for purposes of this
7 question I'm 100 percent load factor which is impossible,
8 of course
9 A Okay.
10 Q -- but let's say I'm 100 percent and I'm
11 consuming 100 megawatts steadily 24/7 all year. Now,
12 just as a matter of common sense, I would look at this
13 material and say to myself, if costs are variable over
14 time, which, obviously, a cost of service study
15 implicitly assumes is the case, my rates or my costs, the
16 costs that I'm causing the Company to incur, should be
17 lower than average in May. I can make that as a common
18 sense deduction from this information. I could reach
19 that conclusion, couldn't I?
20 A From just this sheet here?
21 Q Yeah.
22 A I don't know that you could arrive at that
23 conclusion from just that sheet. I think what you said,
24 yes, if the maj ori ty of this customer's bill is made up
25 of energy-related costs, you could make that assumption,
CSB REPORTING
[phone]
581 TATUM (X)
Idaho Power Company
.
.
.
1 but I don't think you could know, you can't know for
2 certain based on this information.
3 Q Well, we could get a strong suspicion,
4 couldn't we? Look, let me ask it another way: Look at
5 the total cost of $88 million on the right-hand side of
6 what amounts to line 6. Now, if you look over at July
7 and August, you'll see that more than half of that net
8 power supply cost is incurred in those two months;
9 correct?
10 A Correct.
11 Now, that shows a pretty strongly peakingQ
12 si tuation in July and August as at least to energy;
13 correct?
14 A Correct.
15 Q And we also, by the way, we know that to
16 be the case for the capacity or demand charges as well,
17 don't we?
18 Those months are also high capacity costA
19 months as well, yes.
20 Q Okay; so we can say to ourselves those are
21 high cost months and anything that would tend to shift
22 costs or cost' responsibilities from the highest cost
23 month to costs that are low cost months on average or
24 below average costs would inordinately shift costs to
25 high load factor customers, would it not?
CSB REPORTING
[phone]
582 TATUM (X)
Idaho Power Company
.
.
.
1 A You know, are we -- do we have a starting
2 point here?
3 Q Okay, let me ask something else and one
4 more thing. The reason why I handed out Mr. Hessing's
5 exhibi t as 709, Mr. Hessing has a calculation that does
6 not appear on Mr. Said's. If you'll look at the third
7 line, you will see there a cost per megawatt-hour
8 calculated. Do you see that calculation?
9 A Yes.
10 Q And over on the far right-hand side in
11 that line, you'll see a number under the word Annual in
12 that same line and let me represent to you, and it didn't
13 print very well, but that number is 5.3 and what that
14 number actually is is an average cost per megawatt-hour.
15 A Okay, yes.
16 Q Now, once again comparing that average,
17 looking across, we can see, as we would expect, July is
18 almost three times the average cost, August roughly
19 two-and-a-half times, but May is less than 1/10th of the
20 average cost per megawatt-hour.
21 A Yes.
22 Don't you think including May, and I pickQ
23 May, I'm not going to go through it with September, which
24 is not as dire, but don't you think that including May in
25 your peak months is apt to distort the results of the
CSB REPORTING
[phone]
TATUM (X)
Idaho Power Company
583
.
10
.
.
1 cost of service study?
2 A Well, as I said earlier, we included all
3 marginal energy costs or we included marginal energy
4 costs as weighting factors in all months for energy.
5 Q Okay.
6 A And we -- or I included those amounts at
7 the levels produced on the previous exhibit, Mr. Said's,
8 is it 709? 708?
9 Q He's 708.
A Okay. Those monthly energy, marginal
11 energy, costs were used after including the variable O&M
12 to weight each month throughout the year for the
13 energy.
14 Okay. Now, let's move on just briefly toQ
15 another topic contained within this exhibit. Again, I
16 asked you earlier about Mr. Said's statement to the
17 effect that if a model produces unreasonable results,
18 then the model should be corrected and I don't think any
19 of us would disagree with that; correct? You wouldn't
20 disagree with. that?
21 A No.
22 I want you to look down to the marginalQ
23 cost of energy determination and if you look over to the
24 far right, you'll see a column headed Annual and -- well,
25 let me ask the question: That's the average annual
CSB REPORTING
[phone]
584 TATUM (X)
Idaho Power Company
.
.
1 marginal cost, is it not?
2 A I believe so, yes.
3 Q Okay. Now, what's interesting here is if
4 you look to the column under June which the Company's
5 rate design witnesses include, as they should, in the
6 June, July and August high cost periods for rate design
7 purposes; is that correct?
8 A Are you asking me about what our rate
9 design witnesses have prepared?
10 Q Yes. If you don't know, that's fine.
11 A I believe that they used marginal costs in
12 some instances, yes.
13 Q Well, do you know whether they in fact
14 weight June, July and August more heavily in terms of the
15 rates they ultimately designed for virtually every
16 customer class, I believe? If you don't know, that's
17 fine.
18 A I believe that's accurate, yes.
19 Q Okay. Now, returning to June, what's
20 strange about this is the very lowest marginal cost
21 according to the model is June. How can you explain that
22 result?
23 A That marginal cost, the marginal cost of
24 energy is lowest during June?.25 Q Uh-huh.
CSB REPORTING
[phone]
585 TATUM (X)
Idaho Power Company
.
.
.
14
15
i A Well, I would imagine it has to do with
2 streamflows at that particular time and the availability
3 of hydro generation, low marginal cost.
4 Q But if that were the case, we would expect
5 that that number that we see for total costs under June
6 would be considerably lower than it is, would we not?
7 A Can you restate your question, please?
8 Q Well, the total cost for June is
9 $9,601,000, and in Mr. Hessing's exhibit, the average
10 cost of June is 6.8 above the 5.3, so those total costs
11 and the individual unit costs are higher in June than the
12 average. How can the marginal cost be the lowest
13 marginal cost of the year? I cannot think of any
explanation for that.
A I just gave you my or what I believe to be
16 the case.
17 Q Okay, one final area. Let's turn to your
18 rebuttal testimony, if you would. Page -- bear with me a
19 second, I lost my page cite. Oh, actually, there's two
20 final areas. You're rebutting, on page 12 you're
21 rebutting, Dr. Reading's testimony in which he argued for
22 75/25 demand to energy split for hydro production plant.
23 Do you recall that testimony? Do you see that testimony
24 there?
25 A I do. I'm on page 12 of my rebuttal.
CSB REPORTING
[phone]
586 TATUM (X)
Idaho Power Company
.
.
20
21
22
1 Q Okay, and you say -- you rej ect it because
2 it's -- you rej ect the fact that PacifiCorp' s approach,
3 which is what Dr. Reading is using there, and you say it
4 was simply accepted by PacifiCorp because it falls wi thin
5 the middle range of reasonable approaches. Do you see
6 that testimony?
7 A I do.
8 Q Where does the -- for instance, in the
9 base study allocation or the modified base study, of
10 course, the allocation is 59 percent to energy, is it
11 not?
12 A Correct.
13 Q Doesn't that fall outside the range of
14 what the Rocky Mountain witness testified would be
15 reasonable on its face?
16 A No, I don't believe so.
17 Q One more thing. In your defense of the
18 3CP/12CP method, you say on page 20, line 22
19 A Are we still on my rebuttal?
Q We are, I'm sorry.
A Okay.
Q There you say that your approach is
23 similar to the base-intermediate-peak method endorsed by
24 the National Association of Regulatory Utility.25 Commissioners in its most recent cost allocation manual.
CSB REPORTING
[phone]
587 TATUM (X)
Idaho Power Company
.
.
20
1 In fact, the NARUC cost allocation manual doesn't endorse
2 any cost of service method, does it?
3 A Okay, it's a method included in the manual
4 that is supported or recommended as one to be
5 considered.
6 Q And in fact, it's one of many. As I
7 recall, the summary document, which I have here
8 someplace, I believe there's a dozen generic types that
9 are discussed and then subsets of each of those; isn't
10 that true?
11 A There are a number of different approaches
12 covered in the manual, correct.
13 Q And NARUC doesn't profess to choose one or
14 recommend one over the other, does it?
15 A No. I guess what I was meaning there is
16 it's one of the methods that they endorse or that is
17 included in the manual for consideration.
18 MR. WARD: Okay, that's all I have,
19 Madam Chair.
COMMISSIONER SMITH: Thank you, Mr. Ward.
21 Mr. Olsen.
22
23
24.25
MR. OLSEN: Thank you, Madam Chair.
CSB REPORTING
[phone]
588 TATUM (X)
Idaho Power Company
.
.
.
1 CROSS-EXAMINATION
2
3 BY MR. OLSEN:
4 Q Mr. Tatum, earlier today we had heard
5 Mr. LaMont Keen testify about some of the driving factors
6 behind this rate case and one of them, not the sole one,
7 was growth on the system; is that correct?
8 A Yes.
9 Q Okay. Now, the irrigators' expert in this
10 case, Mr. Yankel, has provided testimony, direct
11 testimony, that addresses the, this fact with respect to
12 the irrigation class. Have you read that testimony?
13 A I have.
14 Q Okay. Do you know of any reason to
15 dispute the fact of the point he makes that the
16 irrigation class has not been growing in the last 10 to
17 20 years?
18 A Well, I think it does depend on growing
19 from what perspective, I guess, that Mr. Yankel
20 introduces a number of different measurements of growth,
21 growth in terms of energy, growth in terms of demand.
22 One that I don't recall that he pointed out was growth in
23 customers which I believe there has been growth in
24 irrigation customers over the time period that Mr. Yankel
25 covered.
CSB REPORTING
[phone]
TATUM (X)
Idaho Power Company
589
.
.
1 Q i would agree with you on that, but with
2 respect to demand and energy, it's been relatively flat;
3 correct?
4 A I think it's -- I think Mr. Yankel has all
5 the figures in his testimony, but I think there's been
6 slight growth in demand and a slight contraction in
7 energy consumption over the period, 15-year period, that
8 Mr. Yankel covers.
9 MR. OLSEN: Okay, and may I approach the
10 witness, Your Honor --
II COMMISSIONER SMITH: Yes, you may.
12 MR. OLSEN: -- or Madam Chair.
13 (Mr. Olsen approached the witness.)
14 MR. OLSEN: I'm just going to hand you
15 three papers which are some cost of service study
16 materials that your colleague Ms. Brilz had provided in
17 the 2003 rate case and these are parts of that and if we
18 could have that marked as Irrigator 308.
19 COMMISSIONER SMITH: Is this one exhibit
20 in three parts?
21 MR. OLSEN: In three parts, correct.
22 (Idaho Irrigation Pumpers Association
23 Exhibi t No. 308 was marked for identification by the
24 Notary Public.).25 Q BY MR. OLSEN: Now, these excerpts from
CSB REPORTING
[phone]
590 TATUM (X)
Idaho Power Company
.
.
.
1 the prior testimony of Ms. Brilz more or less are going
2 to correspond to the exhibits in your case, specifically
3 Exhibi t 41 correlates to Exhibit 66 in your direct
4 testimony, and Ms. Brilz's Exhibit 43 correlates to your
5 Exhibit No. 70, and then Ms. Brilz's Exhibit No. 40
6 correlates to your Exhibit 86 or, sorry, 68, if you could
7 maybe be ready to turn to those as I ask a couple of
8 questions.
9 COMMISSIONER SMITH: Mr. Olsen, could you
10 repeat that one more time for me?
11 MR. OLSEN: Yes, Madam Chair. Brilz's
12 Exhibit 41 would correlate to Mr. Tatum's Exhibit 66.
13 Brilz's Exhibit 43 would correlate to Tatum's Exhibit 70,
14 and then Brilz' s Exhibit No. 40 would correlate to
15 Tatum's Exhibit 68, and the reason I'm handing these out
16 is just to look at some of these class characteristics of
17 the irrigation class in the '03 case and as they
18 represent here now in the 2008 rate case and so
19 demonstratively.
20 Q BY MR. OLSEN: If you. could turn to what
21 we have marked as our Exhibit 308 and it's Brilz' s
22 Exhibi t 41, if you could look on the first page there at
23 line 190 over in column H, it provides an amount that
24 is -- of rate base that's allocated to the irrigation
25 class; correct?
CSB REPORTING
[phone]
591 TATUM (X)
Idaho Power Company
.
.
1 A Okay, yes, I'm there.
2 Q Okay, then if you would turn to your
3 Exhibit 66, I think is the comparable exhibit, and it's
4 based on the 3CP/12CP cost of service study?
5 A Yes.
6 Q And we show there in line 12, sorry, line
7 13 -- sorry, 10, rate base of approximately 290, et
8 cetera. Now, just eyeballing it there, it looks like
9 there's about. a five percent increase in rate base that's
10 being allocated to the irrigation case from the '03 rate
11 case to the '08 rate case; is that fair?
12 A It sounds about right.
13 Q Or subj ect to check, you can do the
14 numbers,I think it's actually 5.2, but it's right around
15 five percent.
16 A Okay.
17 Okay, if you could turn to Exhibit 308,Q
18 Brilz's Exhibit 43, and this is just -- I've just
19 provided the first page of that exhibit. As you can see,
20 it had 22, but I'm just looking at the normalized sales
.
21 for 2003 shown for the agricultural class on line 7. We
22 have a 1,620,931 number and that corresponds to your
23 Exhibi t No. 70 and we have the irrigation service
24 normalized sales for 2008 on line 6, 1,551,322,661; is
25 that correct?
CSB REPORTING
(208) 890~5198
592 TATUM (X)
Idaho Power Company
.1 A You're looking at energy sales?
Yes, energy sales from Ms. Brilz's exhibit
3 and your current 2008 exhibit.
2 Q
We're on Exhibit 70; correct?
Yes.
Okay, I'm there.
Okay, and just doing the delta, the
8 difference between the 2003 sales and the 2008 normalized
4 A
9 sales, we have another difference of approximately five
5 Q
10 percent, subject to check, I would represent to you.
.
6 A
Okay, I'll take your word for it.
Okay. Now, we'll turn to the last one,
13 Brilz's Exhibit 40 in our exhibit and this shows the
18 A
7 Q
14 total demand. It doesn't have a line number there, but
19 Q
11 A
15 on her exhibit there on the far left-hand column, it says
12 Q
16 total, that we follow that over for the irrigation class
17 where the number is 3,376,732.
Yes, I see that.
Okay, and then if you would look at your
20 Exhibi t No. 68 which is the comparable.
21
22
A
Q
23 class there?
.24 A
Yes.
What total does it show for the irrigation
2,911,274.
Now. Now the delta there I would25Q
CSB REPORTING
[phone]
593 TATUM (X)
Idaho Power Company
.
.
.
1 represent to you, subj ect to check, is right around a
2 drop in the demand, peak demand, of about 14 percent.
3 A Okay.
4 Q Okay. Now, earlier I tried to talk to you
5 . about some characterizations about the irrigation class
6 in Mr. Yankel' s testimony, but looking at these numbers
7 as far as amount of rate base assigned at the same time
8 sales are going down, also demand is going down, is that
9 a logical result?
10 A I think it's a result that's consistent
11 with updating the demands and the energy for the
12 irrigation class.
13 Q And consistent in what way?
14 A Consistent that if it had grown, the
15 irrigation class would have been allocated a larger share
16 of costs than they did under the study that I prepared,
17 so because the demand and energy values decreased, then
18 the irrigation customers are receiving a lower share of
19 costs than they would have otherwise if their loads had
20 stayed the same.
21 Q Okay; so the share of costs they are
22 recei ving, though, we have some that I think that are,
23 what I would term like Mr. Keen talked about,
24 improvements in system integrity, you know, just general
25 maintenance, those type of costs, but there's a
CSB REPORTING
[phone]
594 TATUM (X)
Idaho Power Company
.
.
.
1 significant chunk there at least due to growth;correct?
A I agree,yes.
Q And from what we can see with these
numbers,the irrigation class is not growing in terms of
energy sales or demand;correct?
2
3
4
5
6 A These numbers show that they decreased
7 since the '03 case, yes.
8 Q All right; and then I come to the question
9 as it relates to increased costs on the system due to
10 growth, does it seem logical that we would be allocated a
11 disproportionate share of those costs?
12 A Are you saying that you're receiving
13 you believe that you' re receiving a disproportionate
14 share or a share in proportion to your current loads?
15 Q Well, I believe you're familiar with Mr.
16 Yankel 's testimony, I'll let him speak to that, but does
17 it seem to make sense that we're getting allocated a
18 significant amount, more amount, of costs, yet we're not
19 growing in that sense, because we know a slice of that is
20 related to growth, but we're not growing. Does that seem
21 fair, I guess, is what I'm asking?
22 A I think the study that I've prepared
23 resul ts in a cost allocation that is reflective of costs
24 that are being imposed on the system in the test year.
25 Q Okay. Now, when you say the test year,
CSB REPORTING
[phone]
595 TATUM (X)
Idaho Power Company
.
.
1 let's talk a little bit more about that, okay?
2 A Okay.
3 Q Now, when you look at the test year data,
4 you look at the samples and it just says at a point in
5 time here are the people that are causing costs on the
6 system; is that correct, a fair characterization?
7 A Sure, yes.
8 Q Does that test data distinguish among the
9 customer classes that make up that test year data, who's
10 growing and who's not growing?
11 A No, we're looking at the loads during the
12 test year period.
13 Q Yes.
14 A Yes.
15 Q Does it distinguish among the classes
16 who's contributing more or less at that point in time?
17 A Contributing, yes, I think it does.
18 Q In what way does it do that?
19 A Contributing to the costs in the test
20 year?
21 Q Well, I'm just saying the -- let's say the
22 residential class demand is X, you know, and everybody
23 has a slice that makes up that study.
24.25
A Right, yes, I believe that it does. To
the extent that others are growing at a faster rate, then
CSB REPORTING
[phone]
596 TATUM (X)
Idaho Power Company
.
.
.
1 to the extent that one class is growing at a faster rate
2 than the other class, the share of costs that the class
3 that is growing would receive would be larger than it
4 would have been had they not grown at all, so the
5 allocation factors adj ust for the changes in the loads in
6 each customer class in each case, in each test year, so
7 we're using the loads that occurred during the test year
8 and we're allocating costs accordingly.
9 But it doesn't take into account how youQ
10 got there, it just looks at that test year; correct?
11 It looks at the costs in the test year andA
12 allocates on the basis of the characteristics of each
13 class in that test year, correct.
14 Q Okay; so let's look at the -- just say
15 hypothetically in 2003, here the residential class has
16 grown from that until this current rate case, so you're
17 saying the cost of service study has increased its cost
18 allocators in general?
19 Yes, to reflect the growth in theA
20 residential if growth had occurred in the residential
21 class as you described, that would be reflected in the
22 allocation factors that we've used, that I've used in
23 this case.
24 Now, would an offshoot of that growth thatQ
25 has occurred, would there be additional revenue allocated
CSB REPORTING
[phone]
597 TATUM (X)
Idaho Power Company
.
.
.
1 to that class, also, under your model?
2 A Yes, revenue is assigned to that class
3 based on what's expected to occur in the test year or
4 would occur in the test year.
5 Q What would happen in the irrigation class,
6 let's say that you just saw the numbers, it's not
7 growing, is it getting assigned any additional revenue
8 related to the growth that is assigned to it?
9 A It's assigned the portion of revenue that
10 it's expected to provide in the test year.
11 Q But then you use that to determine its
12 rate of return there and if it's not actually having any
13 growth, would it have any additional revenue allocated to
14 it?
15 A It's based on the same loads that we used
16 to derive the allocation factors. It's the same numbers,
17 so the loads that are used to determine the revenue
18 amount that each class provides are the same loads that
19 we use for the allocation factors, so it's consistent in
20 that way, so as the allocation or as the loads that drive
21 the allocation factors to change, they would also drive
22 the revenue to change for each customer class
23 consistently.
24 Q I'd like to focus on a little bit
25 different direction with respect to you have critiqued
CSB REPORTING.
[phone]
598 TATUM (X)
Idaho Power Company
.
.
.
1 Mr. Yankel' s methodology that he's put forward in his
2 direct testimony related to growth corrected allocators;
3 is that correct?
4 A Yes.
5 Q Now, have you done any -- based on your
6 recommendations on changing how a growth corrected
7 allocator would be used, what would be the approximate
8 increase needed for the irrigators if you used your
9 changes in his growth corrected cost of service study, if
10 you have made such a determination?
11 A Can you refer in my testimony where you
12 are--
13 Q Certainly. It would be --
14 A addressing?
15 Q in your direct or your rebuttal
16 testimony, yes, on page 6 and carries over to page 7.
17 Beginning on line 11 on page 6 there, you talk about if
18 the Commission determines that the growth-related issues,
19 et cetera from there on, so if you want to refresh your
20 recollection there.
21 A Okay.
22 Q In that beginning on line 11 and that
23 exchange right there, you talk about a couple of
24 adjustments that you would recommend the Commission would
25 adopt and all I'm trying to ask, have you made any
CSB REPORTING
[phone]
599 TATUM (X)
Idaho Power Company
.
.
1 projections with your adjustments how that would affect
2 the allocations of the irrigation class under your
3 preferred cost of service methodology?
4 A Well, I just want to point out that I'm
5 not recommending that the Commission adopt this
6 methodology.
7 Q Okay.
8 A The question says that if the Commission
9 determines that the growth-related issues that Mr. Yankel
10 identifies have merit, are there any adj ustments to his
11 methodology that could be made to produce more reasonable
12 resul ts, and I've suggested a couple of adj ustments that
13 could be made and I did not produce a cost of service
14 study that utilized the allocation factors that would be
15 produced under this adjusted methodology.
16 Q Okay. Let's look at page 8 in your
17 rebuttal testimony.
18 A Okay.
19 Q Mr. Yankel also made the suggestion that
20 in looking at this rate case that the Commission should
21 take into account the effects that a changed Irrigation
22 Peak Rewards Program would have on the allocators of the
23 irrigation class; is that correct?
24.25
A Yes.
Q Now, you've criticized that position of
CSB REPORTING
[phone]
600 TATUM (X)
Idaho Power Company
.
.
.
1 Mr. Yankel based on the fact that it hasn't gone into
2 effect yet and, in essence, would be speculative; is that
3 a fair characterization?
4 A That was one of my criticisms, yes.
5 Q Okay. Now, could you explain to me how
6 his suggestion of taking into account this new irrigation
7 program is different from, you know, Idaho Power's
8 request in this case to use a future test year and
9 adj ustments based on some kind of forecast of what was
10 going to happen during the year?
11 A Other than the fact that the program
12 hasn't been approved yet --
13 Q Yes.
14 A -- or the modifications to the program
15 have not been. approved?
16 Q Let's assume that they will, but I mean,
17 you know, we haven't seen what the effects would be, I
18 guess, at this point in time in concrete numbers.
19 A Okay. Well, I feel like that's still a
20 sizeable uncertainty, possibly not that it's approved,
21 but maybe when it's approved, if there are any
22 modifications to the program as a result of the approval.
23 You know, those factors that I just mentioned will impact
24 the Company's ability to meet its targets for the program
25 or the achievable potential that we've identified, and
CSB REPORTING
[phone]
601 TATUM (X)
Idaho Power Company
.
.
.
1 that leads me to the second piece which that achievable
2 potential that we've identified, that the Company Idaho
3 Power has identified, for 2009 is a much lower number
4 than what Mr. Yankel has identified which can demonstrate
5 the fact that there's some uncertainty there, that we
6 really don't know exactly what the impact is and we're
7 talking about 2009. Our test year is 2008.
8 Q Okay. Let's just assume that the changes
9 in the Peak Rewards Program are approved, okay? I just
10 want to talk a little bit about the effects of that and
11 how that would affect the irrigation class in future rate
12 cases.
13 A Okay.
14 Q Okay; so you worked on the Peak Rewards
15 Program, correct, the proposed changes that's currently
16 before the Commission?
17 A Yes, I did file testimony in that case.
18 Okay. Now, do you expect the size of thatQ
19 program to increase as far as the amount of peak load
20 shaved over the current existing program if it's
21 approved?
22 Would you restate your question, please?A
23 I'm just saying on the current baseQ
24 program if the amount of load -- do you expect that the
25 amount of load that will be shaved under the Peak Rewards
CSB REPORTING
[phone]
602 TATUM (X)
Idaho Power Company
.
.
20
21
22
1 Program will increase under the new program?
2 A Yes, I believe that the new -- the
3 modifications to the program will result in additional
4 load reduction produced by that program --
5 Q Okay.
6 A -- in future years.
7 Q And subj ect to check, it was estimated, I
8 think, possibly in your testimony or one of your
9 colleagues that the net effect if it's approved in 2009
10 would be about 112 megawatts; is that correct?
11 A Correct.
12 MR. OLSEN: Can I have just a brief recess
13 real quick?
14 COMMISSIONER SMITH: We'll be at ease for
15 just a minute.
16 (Pause in proceedings.)
17 MR. OLSEN: I'm ready again.
18 COMMISSIONER SMITH: Mr. Olsen, I'm sorry,
19 I didn't hear you.
MR. OLSEN: I'm ready again.
COMMISSIONER SMITH: Okay.
Q BY MR. OLSEN: Just one last question,
23 Mr. Tatum. If there is an increase in the amount of load
24 that's shaved on the peak, the system peak, as a result.25 of the proposed changes to the Peak Rewards Program, what
CSB REPORTING
[phone]
TATUM (X)
Idaho Power Company
603
1 effect would that have in general on the costs that would.2 be allocated to the irrigation class under your cost of
3 service methodology?
4 A Well, I can't tell you specifically what
5 the results would be of the study, but as I mentioned
6 earlier, to the extent that the coincident -- the
7 irrigation class's share of the system peak is reduced,
8 that would reduce the cost allocation or the amount of
9 costs allocated to the irrigation class, and when I say
10 costs, I'm specifically talking about generation,
11 production-related costs, demand-related costs, the costs
12 that are allocated according to those factors..13 Q Okay, and so in general, it's fair to say
14 it benefits it in that the cost allocator can be lower,
15 therefore, our revenue requirement, et cetera as it flows
16 through would be lower; is that a fair characterization,
17 Mr. Tatum?
18 A I think there's potential for that to
19 occur.
20 Q Okay. Now, also doesn't the whole system
21 benefit by a reduced summer peak as well?
22 A Yes, the assumptions in the value of the
23 program is that we would avoid more expensive capacity
24 and so to the extent that that occurs, we would have.25 reduction in costs that would have occurred had the
CSB REPORTING
[phone]
604 TATUM (X)
Idaho Power Company
.
.
.
1 program not been operating.
2
3 Madam Chair.
4
5 Mr. Purdy.
6
7
8
9 just a couple.
10
11
12
13
MR. OLSEN: I have no further questions,
COMMISSIONER SMITH: Thank you.
MR. PURDY: I have none. Thank you.
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Thank you, Madam Chair,
CROSS-EXAMINATION
BY MR. RICHARDSON:
14 Q Mr. Tatum, have you reviewed Dr. Reading's
15 and Staff witness Hessing's rebuttal testimony?
16 A Yes, I have.
And do you recall where Mr. Hessing stated
18 that the current methodology developed in 2004 that
17 Q
19 establishes coincident peak demands that are used in
20 developing cost of service allocation factors has
21 unintended consequences, do you recall him stating
22 that?
23 A
24 his testimony.
25 Q
Yes, I think I remember that portion of
And do you remember what those unintended
CSB REPORTING
[phone]
605 TATUM (X)
Idaho Power Company
.
.
.
1 consequences might be?
2 A Can you point me to the page in
3 Dr. Reading's testimony?
4 Q Actually, it's in Mr. Hessing's testimony.
5 A Mr. Hessing's testimony, then?
6 Q On page 11, lines 5 to 18.
7 A It's page 11, line 5?
8 Q Lines 15 to 18.
9 A I'm sorry, one more time.
10 Q I believe it's on page 11, lines 15 to 18.
11 A Okay, and can you repeat your question,
12 please?
13 Q Certainly. I was asking if you recall
14 what those unintended consequences might be.
15 A Okay, well, as I'm looking at
16 Mr. Hessing's testimony, seeing in that section talking
17 about trends that have occurred since the '03 case, is
18 that the section that you're referring to?
19 Q I believe it is. I don't have his
20 testimony, frankly, right in front of me, but I have it
21 in my notes that we're looking at page 11, lines 15 to
22 18. We're pulling it up now.
23 A I'm just having a tough time tying the
24 unintended consequences to the section you're pointing me
25 to.
CSB REPORTING
[phone]
606 TATUM (X)
Idaho Power Company
.
.
.
18
1 COMMISSIONER SMITH: Are you in his
2 rebuttal?
3 THE WITNESS: I'm in the direct. That's
4 possibly where I'm going wrong, then.
5 MR. RICHARDSON: I'm sorry, it's his
6 rebuttal testimony at page 11.
7 THE WITNESS: Okay, I actually don't have
8 a copy of Mr. Hessing's rebuttal testimony.
9 Q BY MR. RICHARDSON: I don't think you need
10 a copy. You said you recalled his discussion about
11 unintended consequences and I was wondering if you
12 recalled what some of those unintended consequences might
13 be.
14 A Of the methodology that stemmed from the
15 workshop process?
16 Q Correct, the new methodology.
17 (Mr. Kline approached the witness.)
THE WITNESS: Thanks, Bart. Mr. Hessing
19 describes systematic changes that may not be recognized.
20 That's the way I understand his testimony.
21 Q BY MR. RICHARDSON: Would you say that one
22 of those systematic changes has had a significant impact
23 on the allocation of revenue responsibility among
24 customer classes between the 03-13 case that was last
25 li tigated and the rate cases filed by the Company since
CSB REPORTING
[phone]
607 TATUM (X)
Idaho Power Company
.
.
.
1 then?
2 MR. WALKER: Madam Chairman, I'm going to
3 obj ect to that. I think perhaps counsel should ask
4 Mr. Hessing what systematic changes he's referring to
5 because the testimony is not identified.
6 COMMISSIONER SMITH: Mr. Richardson.
7 MR. RICHARDSON: I was just asking if this
8 witness had an understanding. I wasn't cross-examining
9 this witness on Mr. Hessing's testimony.
10 COMMISSIONER SMITH: I'll allow the
11 wi tness to respond to the question that was just asked.
12 MR. RICHARDSON: Thank you, Madam Chair.
13 THE WITNESS: Could you ask that question
14 again, please?
15 Q BY MR. RICHARDSON: Would you say that
16 this change has had a significant impact on the
17 allocation of revenue responsibility among customer
18 classes between the 03-13 case that was last litigated
19 and the rate cases filed by the Company since?
20 A I want to make sure that I understand your
21 question. Is your question that the implementation or
22 the use of the methodology that was agreed to in the
23 workshop process, is that responsible for changes in the
24 cost of service results since the '03 case?
25 Q Well, specifically what I'm thinking of,
CSB REPORTING.
[phone]
608 TATUM (X)
Idaho Power Company
.
.
.
1 Mr. Tatum, is the move from test year, coincident factors
2 for the test year to the median of the past five years,
3 that change. Has that had a significant impact on the
4 allocation of revenue responsibility among customer
5 classes?
6 A I don't think it has had a significant
7 impact, no.
8 Q You wouldn't agree that it's been a factor
9 in the shift of revenue responsibility to the high load
10 factor customers from the residential and commercial
11 class?
12 A You know, I think, really, it's going to
13 depend on I mean, you're referring to a methodology
14 that utilized a single year of demand factors versus a
15 methodology that utilizes five years and then takes the
16 median. It really just depends on which single year
17 you're using that would produce a result that you're
18 describing. I guess the answer is that it depends.
19 Q Well, in this case we're talking about the
20 most recent year, so with that in mind, what would your
21 answer be?
22 A If we were to use the most recent year
23 data or factors for the most recent year, which I'm
24 assuming you're referring to 2007 --
25 Q Yes, I am.
CSB REPORTING
[phone]
609 TATUM (X)
Idaho Power Company
.
.
.
17
1 A -- as compared to the use of the median
2 factor approach and you're asking me if that, if the use
3 of the '07 factors in deriving the demand allocators
4 would produce a result in the cost of service study that
5 would shift more costs or more or less costs to high load
6 factor customers?
7 Q That was the question, if it would shift
8 more revenue responsibility to the high load factor
9 customers vis-a-vis the residential and commercial class.
10 A I believe that the use of the 2007 factors
11 would reduce the cost responsibility of the high load
12 factor customers just by the nature of the year of 2007.
13 That result could change if the year used was 2008 or
14 2006.
15 Q But I wasn't asking you about 2008 or
16 2006, so I take it your answer is yes?
A If I'm understanding your question, yes,
18 the use of the 2007-based factors would result in less
19 cost responsibility for higher load factor customers in
20 general.
21 Q Thank you. Now, this is just a
22 housekeeping question. Mr. Hessing accepts Dr. Reading's
23 use of the test year coincident peak factors rather than
24 the five-year average used by the Company and he a
25 provided a new cost of service study run based upon
CSB REPORTING
[phone]
610 TATUM (X)
Idaho Power Company
.
.
.
18
1 Staff's revenue requirement recommendations. Did you
2 have -- do you accept that Mr. Hessing has accurately
3 performed the cost of service runs based on this
4 change?
5 A I can't verify that. I don't know.
6 Q Did you look at that at all?
7 A I did look at the results that he
8 produced. I haven't looked at the model that he
9 produced.
10 Q And did anything jump out at you in
11 looking at the results that suggested they might not be
12 accurate?
13 A No. My high level look, I didn't see
14 anything that jumped out at me as being incorrect or
15 flawed in any way.
16 MR. RICHARDSON: Thank you, Madam Chair.
17 That's all I have.
COMMISSIONER SMITH: Thank you. Mr.
19 Bruder, do you have questions?
20 MR. BRUDER: I do have a number of
21 questions. I will ask if we're going forward if we could
22 have a five-minute break. I do need to feed the meter.
23 COMMISSIONER SMITH: Exactly what I was
24 thinking. Okay, let's reconvene at 10 to 5: 00. It's my
25 intention to at least go until 5: 30.
CSB REPORTING
(208) 890-519ß
611 TATUM (X)
Idaho Power Company
1 MR. BRUDER: Thank you..2 COMMISSIONER SMITH: We will be in recess
3 for a few moments.
4 (Recess.)
5 COMMISSIONER SMITH: All right, we'll go
6 back on the record. Mr. Bruder.
7 MR. BRUDER: Thank you.
8
9 CROS S - EXAMINAT I ON
10
11 BY MR. BRUDER:
12 Q I guess I should say good evening.
13 COMMISSIONER SMITH: Were you on Eastern.14 time when you started this morning? He doesn't remember.
15 Let's move on.
16 MR. BRUDER: I would say I was confused is
17 what I would say.
18 COMMISSIONER SMITH: All right, thank you.
19 Q BY MR. BRUDER: Now, five years ago this
20 Commission approved a methodology under which load factor
21 was used to classify energy; is that correct?
22 A Yes, correct.
23 Q And that methodology also averages 12
24 unweighted coincident peaks with 12 weighted coincident.25 peaks in order to allocate demand; is that correct?
CSB REPORTING
[phone]
612 TATUM (X)
Idaho Power Company
.
.
.
18
19
20
1 A The methodology used in that case, the
2 '03 case, that you referenced did do that for the
3 demand-related allocation factors for generation and
4 transmission investment.
5 Q Has this Commission approved any different
6 methodology for classifying and allocating IPC' s cost
7 since that 2003 decision?
8 A No.
9 Q Has the Commission addressed that subj ect
10 since the 2003 decision in any formal way?
11 A Other than the workshop that occurred,
12 cost of service workshop, there's been no subsequent
13 Commission review or order related to cost of service.
14 Q Since 2003 when that last study was
15 adopted by this Commission, has the Company become less
16 energy constrained and a good deal more capacity
17 constrained?
A Since that case, is that your question?
Q Yes, it is.
A I can't answer whether they've been more
21 or less capacity constrained since that case.
22 Q So is there another witness who could
23 answer that question?
24
25
COMMISSIONER SMITH: Excuse me, it seems
like we have people listening in on the phone who are not
CSB REPORTING
[phone]
613 TATUM (X)
Idaho Power Company
.
.
.
1 muted, so we're hearing your conversation. Please mute
2 your phones. Thanks.
3 THE WITNESS: I think, yes, based on our
4 IRP analyses that have occurred since that time, I think
5 possibly Mr. Keen testified earlier today to the fact
6 that the Company's peak or growth in peak usage is
7 outpacing the growth in energy.
8 Q BY MR. BRUDER: Which translates, at least
9 one way it translates, to saying that the Company has
10 become a good bit more capacity constrained; is that
11 right?
12 A I think that's consistent with that,
13 yes.
14 Q And so if this Commission were going at
15 this time to adopt a change in the way that it classifies
16 and allocates costs, that change should be in the
17 direction of classifying and allocating more costs on the
18 basis of demand to reflect the classes' usage at peak; is
19 that not correct?
20
21
A I think that's correct, yes.
Q Okay, let's look at what the Company is
22 recommending in this proceeding. The Company is
23 recommending, as I have understood it, what you call a
24 3CP/12CP methodology that would in effect replace the
25 methodology that the Commission approved in 2003; is that
CSB REPORTING
[phone]
614 TATUM (X)
Idaho Power Company
.
.
.24
25
1 correct?
2 A Yes, it would be a modification to that
3 approved methodology.
4 Q Well, it would be a fairly significant
5 modification, would it not?
6 A Well, by looking at the results produced
7 by the two studies, the results aren't significantly
8 different. I think the concepts are different, yes.
9 Q How are the concepts different?
10 A Well, the 3CP/12CP methodology that I
11 proposed, it recognizes that point that you were making
12 earlier on summer peak demands growing --
13 Q If I may, I'LL interrupt you. What I'd
14 like you to address, if you would, is the way the
15 methodology itself works and the differences between the
16 2003 methodology and the one which you now propose. For
1 7 example, in the 2003 methodology, we have, do we not,
18 weighted coincident peaks where weighted coincident peaks
19 are not used in the methodology you propose today; is
20 that correct?
21 A No, that's not correct.
22 Q Okay, please tell me where it's not
23 correct.
A Okay. The. 3CP /12CP approach changes the
way that we would allocate the costs associated with
CSB REPORTING
[phone]
615 TATUM (X)
Idaho Power Company
.
.
.
1 production plant, fixed investment in generation plant.
2 Q It changes that in quite a number of ways,
3 doesn't it?
4 A It does, yes, and so what the method does
5 that I propose is to identify the resources that the
6 Company has added to serve that load during the summer
7 peaks which has been simple cycle combustion turbine
8 generation.
9 Q Again, I'm going to ask you to speak, if
10 you would, to the actual steps that are involved in the
11 new methodology relative to the old rather than speaking
12 conceptually as you are. For example, if you say that in
13 the new methodology you still have weighted coincident
14 peaks, where would we find that in the new methodology?
15 A The difference in the derivation of the
16 allocation factors between the base case which
17 represented as being --
18 Q Pardon me for interrupting, but I think
i 9 maybe I can clear this up and I think I should have said
20 that at the outset. It's my understanding that what the
21 Company is really recommending is the 3CP/12CP
22 methodology and because of that, I would ask you to
23 address yourself, please, just to methodology rather than
24 the base case and the revised base case or the modified
25 base case.
CSB REPORTING
[phone]
616 TATUM (X)
Idaho Power Company
.
.
.
1 A Okay, I just referenced the base case as a
2 way to differentiate between the methodology that you
3 described that we used that was approved in the '03 case
4 to compare it to the 3CP /12CP. i guess it would be
5 easiest to show the difference by looking at my exhibit.
6 It's Exhibit No. 68. Exhibit No. 68 details the
7 deri vation of the demand and energy allocation factors
8 used in the 3CP /12CP study.
9 Q Uh-huh.
10 A If you look at page 1 of 6, you can see
11 that the allocation factors DI0BS and DI0BNS are
12 allocation factors that have been derived based upon the
13
14
unweighted 12 coincident peak demands for each customer
class, and those allocation factors, the DI0BS and
15 DI0BNS, are used to allocate the costs associated with
16 the Company's investment in generation plant that is
17 categorized as steam production and hydro production, so
18 plant that serves intermediate and base loads. The DI0P
19 allocation factor is used to allocate the costs
20 associated with the Company's investment in peak
21 generation or the simple cycle combustion turbines, the
22 gas-fired turbines, so in the 3CP/12CP, as you can see,
23 it's just a description of the methodology change which
24 is that we're' using for the allocation of the cost or the
25 investment associated with peaking, peak generation,
CSB REPORTING
[phone]
617 TATUM (X)
Idaho Power Company
.
.
.
20
1 using a 3 coincident peak. We're using the coincident
2 peak values for the three summers months to allocate
3 peak, summer peak, or the generation that's been procured
4 to serve that summer peak, and then all other generation
5 investment is allocated according to an unweighted 12
6 coincident peak demand allocation factor.
7 Q Well, the 3CP methodology or portion of
8 the whole methodology that uses 3CP as a basis, that's
9 new, that wasn't used in 2003; is that not correct?
10 A That is new. It was not used in 2003.
11 Q And, again, it's my understanding that in
12 the 2003 study, you all used weighted CP' s where here
13 there are no weighted CP' s, there are merely unweighted
14 CP' s; is that not correct?
15 A For the allocation factors that I just
16 described and' I have an additional portion of my answer
17 that I think can help clarify. If you go to page 3 of 6
18 on Exhibit 68.
19 Q Okay.
A You can see where this details the
21 derivation of the demand allocation factors for the
22 Company's investment in transmission plant, and this,
23 these allocation factors are still derived using that
24 averaging approach. They're derived in the same manner
25 they were derived in the '03 case, so it's just simply
CSB REPORTING
[phone]
618 TATUM (X)
Idaho Power Company
.
.
.
17
18
1 the allocation factors used to allocate the Company's
2 investment in generation plant that have changed. The
3 methodology for allocating transmission investment has
4 not changed. It still utilizes that averaging approach
5 using the marginal cost weighting.
6 Q Okay, but to tie it up, in regard to
7 allocating generation, which is the bulk of these costs,
8 you have made a significant change in that you have
9 discarded the weighted coincident peaks in that
10 methodology; is that not correct?
11 A My recommendation is yes, to use the
12 3CP/12CP methodology.
13 Q Now, looking for one more moment at that
14 change, at that removal of the weighted CP' s, that alone
15 would cause some significant change in the results of an
16 allocation study, would it not?
A It would change, yes.
Q I'm going to ask you, what I said was
19 would it cause a significant change?
20 A I wouldn't characterize it as
21 significant.
22 Q Well, whether we characterize it as
23 significant or not, the effect of using only 12
24 unweighted coincident peaks would cause considerably more
25 energy-related costs to be allocated on the basis of
CSB REPORTING
[phone]
619 TATUM (X)
Idaho Power Company
.
.
.
1 non-system peak usage rather than on the basis of system
2 peak usage; is that not correct?
3 A No, I don't think that is correct.
4 Q Please tell me why not.
5 A We've classified energy-related costs and
6 demand-related costs in the same manner that we used in
7 the' 03 case.
8 Q By that, you mean you used load factor?
9 A Correct.
10 Q Okay, then the question should be directed
11 not to classification but to allocation, can you take the
12 question as being a question about changes in allocation
13 and the effect of the changes in allocation rather than
14 classification? I can repeat the question.
15 A Okay, please.
16 Q We're looking now at the way you recommend
17 that demand-related costs be allocated and you drop, you
18 recommend that you drop, the weighted coincident peaks
19 and use only unweighted coincident peaks. Now, that
20 change causes considerably more energy-related costs to
21 be allocated on the basis of non-system peak usage rather
22 than on the basis of system peak usage; is that
23 correct?
24
25
A No , it's still allocated on system peaks.
It's allocated according to the average of 12 coincident
CSB REPORTING
[phone]
620 TATUM (X)
Idaho Power Company
.
.
.
1 peaks. They're just not weighted by marginal cost, so
2 it's still based on coincident peak responsibility.
3 Q Now, Dr. Goins did a 12CP study whose
4 methodology, as i understand it, is the same as that
5 which the Commission adopted in 2003. That would be
6 found at Dr. Goins' testimony, his direct, at page 20.
7 Have you examined that study?
8 A What is the exhibit again, please?
9 Q I do apologize, I don't have that in front
10 of me. You will find it referenced in Dr. Goins'
11 testimony, in his direct testimony, at page 20. I do
12 apologize, I can get the exhibit. I don't have it in
13 front of me.
14 COMMISSIONER SMITH: What was the page?
15 MR. BRUDER: Twenty.
16 THE WITNESS: Page 20 in Dr. Goins'
17 direct?
18 Q BY MR. BRUDER: Right. I believe the
19 exhibit is attached to the direct. I'm sorry, the
20 exhibits are separate.
21 COMMISSIONER SMITH: That would be Exhibit
22 609 is what's referenced there.
23
24
25
MR. BRUDER: That's my understanding, yes.
THE WITNESS: Okay , it looks like Exhibit
609 is a methödology titled "Peak and Average" and that
CSB REPORTING
[phone]
621 TATUM (X)
Idaho Power Company
.
.
18
1 would not be consistent with any study that the Company
2 produced in '03.
3 MR. WARD: May I interj ect?
4 COMMISSIONER SMITH: Mr. Ward.
5 MR. WARD: I believe it's 610 and 611.
6 COMMISSIONER SMITH: All right, thank you.
7 Q BY MR. BRUDER: Is that correct, Mr.
8 Tatum?
9 A I'm looking at 610 and that does -- that
10 is titled "WI2CP Class Cost of Service Study," but
11 without going directly to the portion of Dr. Goins'
12 testimony, I believe that he mentioned that he was not
13 recommending or in his 12CP or weighted 12CP study, he
14 was not going to be utilizing an averaging approach which
15 was applied to the derivation of the demand allocation
16 factors in the '03 case, so in that way I believe that
17 it's different.
Q I take it from your testimony that you
19 have not examined that study in any depth?
20
21
22
A Oh, I have, yes.
Q Do you find any errors in the study?
A Any errors in the methodology or just
23 errors in how the methodology was applied?
24.25
Q Well, let's start with the methodology.
A Well, I don't know agree with the
CSB REPORTING
[phone]
622 TATUM (X)
Idaho Power Company
.
.
.
1 methodology, no. I'm recommending the 3CP / 12CP approach
2 that I detail in my testimony and it does not -- it's not
3 consistent with what Dr. Goins is proposing.
4 Q Well, my question is if this Commission
5 were to decide to continue to use the methodology that it
6 adopted in 2003, would this study by Dr. Goins be a valid
7 study for it to adopt for that purpose?
8 A I believe, no, that the base case study
9 that I produced would be more reflective of the study in
10 '03, that was approved in '03.
11 Q Why is that?
12 A Well, as I mentioned, the study that you
13 described doesn't use an averaging approach in the
14 derivation of the demand-related allocation factors which
15 was used in the '03 case which would impact the
16 results.
17 Q Is it your testimony that that impact
18 would be significant?
19 A I think we can make a comparison between
20 my base case results and the results that Dr. Goins has
21 provided in 610 and we could assess whether or not that's
22 significant or not.
23 Q Well, that's kind of what I'm asking you
24 to do.
25 A Okay; so I'm looking at Exhibit No. 57 and
CSB REPORTING
[phone]
623 TATUM (X)
Idaho Power Company
.
.
.
17
1 comparing to Dr. Goins' Exhibit No. 610 and yes, the
2 results I would characterize as significantly
3 different.
4 Q I want to look at load factor. As you
5 know, load factor was used in the 2003 study and you
6 recommend that it be used again as a measure of the
7 energy portion of costs. If you know, when did this
8 Commission first adopt load factor as a measure of the
9 energy portion of costs?
10 A Yes, I think I refer to that in my
11 testimony. Just one moment, please. If you look at page
12 10 of my rebuttal testimony, lines 5 through 10, I say,
13 "The Commission has supported the use of the
14 jurisdictional load factor to classify production plant
15 as demand and energy beginning with its Order No. 17856
16 issued in Case No. U-I006-185 in 1983."
Q I take it from that that up to 1983 the
18 Commission had not approved using load factor in that
19 way?
20
21
A I'm sorry, can you repeat that, please?
Q Well, the way I read your testimony, I
22 understood that this Commission may have used load factor
23 in that fashion for your Company beginning in 1983, did
24 it use it for your Company as far as you know before
25 1983?
CSB REPORTING
[phone]
624 TATUM (X)
Idaho Power Company
.
.
1 A I don't know that.
2 Q So it might go back further, might it
3 not?
4 A It could. Based on my research, this was
5 the Order that identified it or approved the use of that
6 method.
7 Q But it's not necessarily the first Order
8 that approved that. I just want to tie that up. That's
9 something we just don't know.
10 A Okay, I don't know that.
11 Q Okay. If you know, what reasons, if any,
12 has the Commission ever stated in orders or any other
13 official source for adopting load factor as a measure of
l4 the energy portion of costs?
15 A You're asking me to cite the Commission's
16 rationale in prior orders for supporting that?
17 Q If the Commission has ever in fact put
18 forth any such rationale. I'm asking you first whether
19 it has put forth any such rationale and if it has, what
20 was that rationale?
21
22
A I don't know at this point.
Q Now, under the new methodology that you
23 recommend, load factor would still be used to classify
24 the energy-related component of costs; is that correct?.25 A Yes, I'm recommending the use of the load
CSB REPORTING
[phone]
625 TATUM (X)
Idaho Power Company
.
.
.
1 factor to classify energy and demand.
2 Q Now, as you know, Dr. Goins has testified
3 that there is no economic or engineering rationale for
4 using load factor to define the energy component of
5 costs. Can you tell me any economic or engineering
6 rationale for using load factor to define the energy
7 component of costs beyond what we find in your prefiled
8 testimony?
9 A I address the rationale in my rebuttal
10 testimony.
11 Q So you do. Let's look at that. That is
12 page 10 at line 14.
13 A Correct.
14 Q By way of explanation as I read it, you
15 say first that use of the jurisdictional load factor is
16 based on the premise that the need for hydro and steam
17 generation plant is driven both by customer demand and
18 energy consumption. I think I understand the premise,
19 but can you explain to me why using load factor in this
20 fashion is in line with that premise so that using load
21 factor in this fashion is appropriate?
22 A Sure. I think to illustrate that point we
23 can talk about how the Company plans to add resources.
24 When the need -- we look at both energy-related
25 deficiencies and peak-hour deficiencies and when we're
CSB REPORTING
[phone]
626 TATUM (X)
Idaho Power Company
.
.
.
1 deficient from an energy perspective, the decision is to
2 add base load or there's a need for base load generation.
3 When we're looking at simply peak, serving just peak
4 hours or very few hours, we would add peak generation or
5 generation resources that have lower fixed costs but
6 higher variable costs. The opposite would be the case
7 for the base load generation which would be driven by
8 energy consumption more so than the peak, coincident
9 peak, demands, so that is a way that you can think about
10 how the Company goes about determining whether or not
11 there's a need for peak generation or base load
12 generation and this concept that I talk about here is
13 consistent with that approach.
14 Q And beyond what you've just said, is there
15 any other rationale for using load factor in this
16 fashion?
17 A Well, I've cited two or made two points on
18 page 10 of my rebuttal testimony. One is that it's
19 consistent with what the Company has done in past cases
20 and that the Commission has approved in past cases. The
21 second point is that because I believe that the need for
22 base load generation is driven by energy consumption by
23 our customers, a portion of that is driven, a portion of
24 that need is driven, by energy and a portion of it is
25 dri ven by the coincident peak demands on a monthly basis
CSB REPORTING
[phone]
627 TATUM (X)
Idaho Power Company
.
.
.
1 that it makes sense to split based on load factor which
2 is a measure of capacity utilization.
3 Q Well , it's a measure of capacity
4 utilization, certainly, but how is it a measure of
5 energy? How is ita measure of the definition of what a
6 portion of costs should be classified as energy? That's
7 what we've had a lot of trouble understanding and I wish
8 you would address.
9 A Sure, okay. Well, load factor is the
10 relationship -- it measures the relationship between
11 average energy and peak demand or average demand and peak
12 demand, I should say, and that aligns quite well with the
13 classification of generation plant as demand related and
14 energy related. Since the coincident peak demands will
15 dri ve the need for capacity based on those coincident
16 peak demands, the energy consumption also drives a
17 portion of, average demands drive a portion of, the need
18 for that capacity as well. The load factor is a logical
19 way to identify the proportions that should be demand
20 related and energy related.
21 Q I'm going to assume that that is the limit
22 of the rationale for this; is that right?
23 A That's the extent of the rationale that
24 I've provided in testimony, yes.
25 Q Okay, thank you. Now, the method that's
CSB REPORTING
[phone]
628 TATUM (X)
Idaho Power Company
.
.
.25
1 used to classify costs as demand related or energy
2 related is important, is it not, because demand-related
3 costs are allocated among ratepayer classes on a very
4 different basis from the way that energy-related costs
5 are allocated among the ratepayer classes; is that
6 correct?
7 A Yes.
8 Q And it's true, too, is it not, that
9 energy-related costs, that is, costs that get classified
10 as energy related, tend to get allocated more to high
11 load factor customers, while demand-related costs tend to
12 get allocated more to low load factor customers; is that
13 correct?
14 A Well, I think to the extent that a
15 customer or a class of customers has more of their bill
16 being composed of energy charges, the impact would be
17 that they would have an increase in their amount, in
18 their bill amount, yes.
19 Q I'm going to take that answer as yes?
20 A Can you repeat the question again,
21 please?
22 Q Sure. Energy-related costs tend to get
23 allocated more to high load factor customers, while
24 demand-related costs tend to get allocated more to low
load factor customers; is that correct?
CSB REPORTING
[phone]
629 TATUM (X)
Idaho Power Company
.
.
.
1 A A larger proportion of energy-related
2 costs would be allocated to higher load factor customers
3 than the proportion of demand-related costs.
4 Q Okay, I think that's a roundabout way for
5 you agreeing with this, is it not?
6 A I'm agreeing with what the way I just
7 stated the way it works.
8 Q Okay, given that if a methodology tends to
9 classify too great a portion of costs as energy, that
10 methodology will tend to allocate too high a level of
11 costs to high load factor customers; is that correct?
12 A It would allocate a greater proportion of
13 costs.
14 Q Well, I'm going to repeat the question
15 now. The question is if a methodology tends to classify
16 too great a portion of costs as energy, that methodology
17 will tend to allocate too high a level of costs to high
18 load factor customers; is that correct?
19
20
A I think that's correct, yes.
Q Now, under the present methodology using
21 load factor to classify costs has the effect of causing
22 about 60 percent of total costs to be energy related; is
23 that right?
24
25
A That's correct.
Q Okay, let's look now at what happens to
CSB REPORTING
[phone]
630 TATUM (X)
Idaho Power Company
.
.
.
1 that 60 percent energy-related costs and the 40 percent
2 demand-related costs when they get allocated among the
3 ratepayer classes. Now, traditionally, generation and
4 transmission which are fixed costs were classified as
5 demand related; is that correct?
6 A Did you say traditionally?
7 Q Yes.
8 A Fixed costs are classified as demand
9 related, is that your question?
10 Q Yes.
11 A In what environment?
12 Q In the environment of electric utilities,
13 say, up until about 1975.
14 A I don't know.I can't speak to what
15 happened prior to 1975.
16 Q Okay, let's take ita different way. When
17 we take the fixed cost of a generation facility, a large
18 base load facility, and we treat a significant portion of
19 those costs as energy related, do we do that on the basis
20 of the theory' that the Company invested money, invested
21 capi tal, in the base load or the intermediate plant for
22 the purpose of attaining lower energy costs than it would
23 otherwise experience?
24
25
A The decision to build a plant would be
based upon in part the energy consumption of Idaho
CSB REPORTING
[phone]
631 TATUM (X)
Idaho Power Company
.
.
1 Power's customers.
2 Q I don't think that's responsive to the
3 question.
4 A Can you ask the question again, please?
5 Q We have a situation here where the fixed
6 costs of large generating facilities, be they base load
7 or intermediate, are treated as energy related. Now,
8 when we treat fixed costs as being energy related, do we
9 do that on the basis of the theory that the company that
10 buil t the fac~li ty invested money in the base load or
11 intermediate for the purpose of obtaining lower energy
12 costs?
13 A I think typically a base load plant is
14 implemented, as I mentioned earlier implemented, because
15 it has, even though it has a high capacity cost, the
16 variable cost or the energy-related cost is lower than a
17 peaking plant in comparison.
18 Q It's a trade-off in which capital costs
19 are chosen as being more advantageous than paying higher
20 fuel costs that would come with a cheaper plant like a
21 combustion turbine; is that right?
22
23
A That's exactly right, yes.
Q And that view, I wouldn't even call it an
24 argument, I would call it a conception or a paradigm, is.25 what we refer to as cost substitution, is it not?
CSB REPORTING
[phone]
632 TATUM (X)
Idaho Power Company
.
.
.
1 A Yes, I believe so, capital substitution.
2 Q And so the theory is the fixed cost,
3 demanded-related cost or base load, substitutes for some
4 significant variable costs that would otherwise be
5 expended on energy; is that right?
6 A Yes, it's being evaluated against other
7 resources that may have higher variable costs.
8 Q And the fixed cost, in effect, substitutes
9 for the variable cost? The fixed capital cost that is
10 sunk into the plant is, in effect, a substitute for the
11 higher fuel costs that are avoided by doing that; is that
12 right?
13 A Yes, there's a different relationship on a
14 per unit basis of fixed versus variable costs with a base
15 load plant than a peaking plant.
16 Q Now, when we classify this significant
17 portion of fixed costs of base load and intermediate as
18 energy, that causes those costs to be allocated on the
19 basis of year-round usage rather than peak usage; is that
20 correct?
21 A It's on the basis of marginal
22 cost-weighted energy consumption, so it's weighted to
23 reflect higher costs. To the extent that the marginal
24 costs show higher costs, say, in the summertime, that
25 would be reflected in those allocation factors, the
CSB REPORTING
[phone]
633 TATUM (X)
Idaho Power Company
.
.
.
17
1 energy-related allocation factors, because of the
2 marginal cost weighting, so it achieves a
3 seasonalization.
4 Q Well, I'm going to ask the question again
5 and ask for a yes or no on this, please. Classifying
6 some significant portion of fixed costs of base load and
7 intermediate plant as energy causes those costs to be
8 allocated on the basis of year-round usage however that
9 is measured rather than peak usage; is that not
10 correct?
11 A A portion of that is allocated based on
12 year-round usage, yes.
13 Q All right, it's my understanding that
14 fixed costs of base load once they are classified as
15 energy are all allocated on the basis of year-round usage
16 rather than one or two peaks; is that not correct?
A Yes, the only portion of the allocation
18 factor that has any sort of recognition of seasonality is
19 the marginal cost weighting.
20 Q You want to remove the marginal cost
21 weighting, don't you?
22 A No, not in terms of the energy allocation
23 factors.
24
25
Q Only the demand?
A Only the demand, yes, only the demand
CSB REPORTING
[phone]
634 TATUM (X)
Idaho Power Company
.
.
.
1 allocation factors related to investment in generation
2 plant.
3 Q Again, if some significant portion of
4 fixed costs of base load and intermediate are classified
5 as energy rather than demand, those costs are going to
6 tend to get allocated to high load factor users rather
7 than low load factor users, aren't they?
8 A Energy-related costs will impact higher
9 load factor customers in the way that we just talked
10 about earlier, yes.
11 Q And so under the capital substitution
12 theory, the capital costs are expended into base load and
13 intermediate because that saves the Company money on
14 fuel, and so now about those lower fuel costs, how are
15 fuel costs classified? In fact, all fuel costs are
16 classified as 100 percent energy, aren't they?
17 A Yes, that's true, that's correct.
18 Q And because they are classified as 100
19 percent energy, they're allocated on the basis of
20 year-round usage rather than peak usage?
21 A They're, again, allocated based on the
22 marginal cost weighted energy allocation factors.
23 Q And that's year-round usage rather than
24 peak usage, is it not?
25 A It is 12 months, yes, it represents 12
CSB REPORTING
[phone]
635 TATUM (X)
Idaho Power Company
.
.
1 months of usage weighted by marginal cost.
2 Q And classifying the lower fuel costs as
3 energy, 100 percent energy, and, therefore, allocating
4 them on that year-round basis also benefits low load
5 factor users, doesn't it?
6 A Allocating lower fuel costs? Can you
7 repeat your question, please?
8 Q Sure. What we produce when we substitute
9 monies, capital monies, invested in plant for monies we
10 would expend on lower -- on fuel costs are lower fuel
11 costs; isn't that right?
12 A Yes, I believe so.
13 Q Okay, and those lower fuel costs get
14 allocated on a year-round basis and that benefits low
15 load factor users, does it not?
16 A They're allocated on the same basis as the
17 other -- all fuel costs are allocated on the same basis
18 and they're allocated on a year-round basis as you
19 mentioned, but they are weighted by marginal cost to
20 shift more of the cost responsibility to the summer
21 months which does benefit low load factor customers.
22 Q But they're not allocated the way demand
23 costs are allocated; isn't that right?
24.25
A No.
Q And when you allocate them on that energy
CSB REPORTING
[phone]
636 TATUM (X)
Idaho Power Company
.
.
.
1 basis, that favors low load factor customers in relation
2 to the way to the results that would be produced if
3 you did it on a demand-related basis; is that correct?
4 A If we allocated -- are we talking about
5 fuel costs?
6 Q Yes.
7 A I don't know. I don't know if we
8 allocate it sounded like your question asked if we
9 were to allocate fuel costs based on a demand or on a
10 demand basis.
11 Q Well, we have taken costs that are
12 tradi tionally considered demand related, fixed costs,
13 sunk costs, and we have classified them here 60 percent
l4 as energy.
15 A Correct.
16 Q Now, on top of that, we classify 100
17 percent of those fuel costs, of all the Company's fuel
18 costs, as energy.
19
20
A Correct.
Q Now, why classify the fixed plant cost
21 that substitutes for expensive fuel as energy related and
22 also classify the resultant lower fuel cost that the
23 capital substitution creates as all energy? If some of
24 the fixed cost of the plant gets classified as energy,
25 doesn't logic require that some significant portion of
CSB REPORTING
[phone]
637 TATUM (X)
Idaho Power Company
.
.
18
19
1 the resultant cheap energy that the base load plant
2 produces be classified as demand related?
3 A No.
4 Q Why not?
5 A Well, the energy, the cost associated with
6 producing that energy is driven by energy consumption. A
7 portion of the investment, the fixed investment, is also
8 driven by energy consumption that we talked about earlier
9 identified by the system load factor. I don't see how
10 you can identify any portion of the fuel cost as being
11 related to demand.
12 Q Well, what we've said is that these
13 capi tal costs cause the Company to be able to buy fuel
14 that is a lot cheaper than it would buy otherwise; is
15 that correct?
16 A In the example of a base load plant, is
17 that what we're still talking about?
Q Yes.
A Okay. The fuel costs for a base load
20 plant are less expensive than other alternatives, yes.
21 Q But the way you're doing it, the plant is
22 getting classified as 60 percent energy and the fuel
23 cost, including the resultant lower fuel cost, is getting
24 classified as 100 percent energy; is that correct?.25 A That is correct.
CSB REPORTING
[phone]
638 TATUM (X)
Idaho Power Company
.
.14
1 Q Well, where in that methodology is there a
2 step that recognizes that the demand-related costs, that
3 the capital costs, have produced significant energy
4 savings? Shouldn't some of that savings be allocated on
5 a demand-related basis? If you're going to take the
6 plant and allocate it on an energy basis, mustn't some of
7 the resultant savings be allocated on a demand basis?
8 A No, I don't think so, no. I think the
9 energy-related costs that we incur as a result of
10 operating the plant are driven by energy consumption and
11 so that is the basis that we've selected to allocate
12 those costs.
13 Q The costs are allocated by the level of
consumption, all of the costs are driven by that, but
15 isn't it true that independent of that, part of what
16 dri ves the overall cost of fuel is the monies that have
17 been invested in the base load plant? The fuel cost
18 would be significantly higher if those monies weren't
19 invested, wouldn't it? That is the very essence of
20 capital substitution, is it not?
21 MR. WALKER: Madam Chairman, I'm going to
22 obj ect at this point. I think we've been down this road
23 several times and the witness has answered his question
24 and given both his opinion and what his cost of service.25 study reflects and I think we're approaching the point
CSB REPORTING
[phone]
639 TATUM (X)
Idaho Power Company
.
.
.
1 where it's just simply getting argumentative.
2 COMMISSIONER SMITH: Mr. Bruder.
3 MR. BRUDER: Your Honor, I think that the
4 witness is deliberately avoiding answering this question
5 directly and my efforts have been toward hearing a direct
6 answer.
7 COMMISSIONER SMITH: Does the witness
8 recall this last question?
9 THE WITNESS: Yes.
10 COMMISSIONER SMITH: All right, do you
11 have an answer?
12 THE WITNESS: I don't know the answer to
13 your question. I think that, you know, as I mentioned,
14 the costs associated with fuel have been allocated on the
15 basis of energy. That is the traditional method that we
16 have used. I think there's still logic behind the use of
17 that methodology. You're asking me to assess a different
18 methodology here today and without further analysis, I
19 don't know that I can give you an answer. I cannot give
20 you an answer.
21 Q BY MR. BRUDER: That's satisfactory. All
22 right, now, we have nearly 60 percent of costs classified
23 and allocated as energy related. That benefits low load
24 factor classes. Now, let's look at how the approximately
25 40 percent of' costs that are classified as demand get
CSB REPORTING
[phone]
640 TATUM (X)
Idaho Power Company
.
.
.
1 allocated among the ratepayer classes. Under the
2 methodology you recommend, some demand-related costs get
3 allocated on the basis of a 3CP and some on the basis of
4 a 12CP method; is that correct?
5 A That is correct.
6 Q And the 3CP' s are representative of months
7 in which the Company experiences its highest monthly
8 peaks; is that correct?
9 A The 3CP
10 Q Yes.
11 A is based on June, the coincident peaks
12 in June, July and August.
13 Q And are those the three months in which
14 the Company experiences its highest monthly peaks?
15 A Typically, yes.
16 Q Now, costs that are allocated on the basis
l7 of the 12CP, that's 12 unweighted monthly peaks, tend to
18 get allocated considerably more to high load factor
19 customers than costs that are allocated on the basis of
20 the 3CP; is that correct?
21
22
A I think that's correct, yes.
Q Now, under this methodology looking at
23 costs that are classified as demand related, how is it
24 determined whether any category of costs will be
25 allocated on the basis of the 12 unweighted monthly peaks
CSB REPORTING
[phone]
641 TATUM (X)
Idaho Power Company
.
.
.
1 or the three coincident peaks?
2 A Well, I describe how I made that
3 distinction in my direct testimony.
4 Q And that's determined on the basis of
5 whether the Company classifies any particular cost as
6 peaking? If it's classified as peaking, it's allocated
7 on the basis of the 3CP? If it's classified as anything
8 but peaking, it's done on the basis of the 12 unweighted
9 CP; is that correct?
10 A Generally, yes. It's the allocation of
11 costs associated with a gas-fired generation plant.
12 Q All right, now, the Company does classify
13 100 percent of combustion turbines as peaking and about
14 nine percent of purchased power as peaking; is that
15 correct?
16 A I believe that's correct, yes.
17 Q But the Company classifies all other
18 demand-related costs as non-peaking and that means that
19 all of demand-related hydro and all of demand-related
20 base load and intermediate and more than 90 percent of
21 purchased power are classified as non-peaking; is that
22 right?
23
24
25
A That sounds correct, yes.
Q Therefore, all of the costs of that 90
percent of purchased power and all the costs of
CSB REPORTING
[phone]
642 TATUM (X)
Idaho Power Company
.
.
1 demand-related hydro and demand-related base load get
2 allocated among the ratepayer classes on the basis of the
3 12 unweighted CP methodology; is that right?
4 A I believe that's correct, yes.
5 Q And that, too, favors low load factor
6 customers, doesn' t it?
7 A I think it would depend upon the load
8 shape of those high load factor customers.
9 Q Isn't it true that any time any cost gets
10 allocated on the basis of the 12 unweighted CP rather
11 than the 3CP that favors low load factor customers?
12 A Costs that would be allocated on the basis
13 of the 3CP method as opposed to the 12CP method should
14 favor low load factor customers.
15 Q Because the one allocates them at peak and
16 the other allocates them
17 A According to the 12 monthly coincident
18 peaks.
19 Q Okay; so to tie it up at this point, the
20 use of load factor to measure energy-related costs and
21 the use of the 12 unweighted coincident peaks to allocate
22 the bulk of demand-related costs both greatly favor low
23 load factor customers. Now, that's the new methodology
24 that the Company recommends. Sir, given the fact that.25 Idaho Power has become significantly more peak
CSB REPORTING
[phone]
643 TATUM (X)
Idaho Power Company
.
.
1 constrained since 2003, is it not illogical to adopt a
2 methodology that allocates more costs to users whose
3 usage levels are relatively level through the year when
4 we know that it is the customers who use more on peak
5 that are driving costs? Why are we taking such an
6 extremely energy
7 COMMISSIONER SMITH: Let's do one question
8 at a time.
9 MR. BRUDER: That's very fair. I do
10 apologize.
11 THE WITNESS: Well, going back to what I
12 think your first question was is why am I proposing the
13 3CP /12CP methodology?
14 Q BY MR. BRUDER:It's not a general
15 question. My question is the Company has become less
16 energy constrained and more peak constrained.
17 A Right.
18 Q Now, a cost of service methodology should
19 follow the facts that underlie cost of service. The fact
20 that underlies cost of service is that the Company has a
21 peaking problem, a peaking difficulty more than an energy
22 difficul ty. Why would you choose a methodology that
23 allocates costs so much more on an energy basis when the
24 fact is that it is peak usage, not energy usage, that is.25 dri ving the costs which we're trying to allocate here?
CSB REPORTING
[phone]
644 TATUM (X)
Idaho Power Company
1.A I'm not recommending a change in
2 allocating the costs based on energy versus demand.I'm
3 simply recommending a change in the way that we allocate
4 our costs associated with generation plant and that is
5 identifying the generation plant that's being added to
6 serve those peak loads and allocate it according to those
7 peak loads. The generation plant that is not, that
8 doesn't -- that exists to serve peak loads in all months
9 of the year are allocated on that basis, 12, the 12
10 coincident peak.
11 Q Is it your testimony that looking at the
12 methodology you now recommend and comparing it to the.13 2003 methodology that a significantly larger percentage
14 of overall costs will be under the new methodology
15 classified as energy related compared to the amount of
16 costs that will be classified or are classified as energy
17 related under. the old methodology?
18 A I think the methodology that I'm proposing
19 classifies costs as energy related and demand related in
20 the same manner as the cost of service study from the '03
21 case.
22 Q Well, very respectfully, we certainly know
23 that they're not classified in the same manner. You have
24 changed the manner. Oh, you're talking about the use of.25 classification. Let's talk about allocation, then.
CSB REPORTING
[phone]
645 TATUM (X)
Idaho Power Company
.
.
.
1 A Okay.
2 Q Is it your testimony that if there's a
3 change from the methodology that has been accepted
4 up until -- let me start again. Let's assume for the
5 moment that the Commission adopts this 3CP /12CP
6 methodology that you recommend. Is it not true that a
7 significantly higher percentage of overall costs will be
8 classified as energy under that methodology than they
9 would have been classified as energy under the old
10 methodology?
11 A No.
12 COMMISSIONER SMITH: Did you mean
13 allocated?
14 MR. BRUDER: Yes, I meant allocated, I'm
15 sorry.
16 THE WITNESS: The answer is still no.
17 Q BY MR. BRUDER: Have you done any figures,
18 any comparisons to see whether that's the fact?
19 A Yes. A comparison can be made between the
20 base case study that I have submitted and the 3CP study,
21 3CP/12CP study that I've submitted. That allows for a
22 comparison between the methodology used in the '03 case
23 and the 3CP /12CP methodology.
24
25
Q Does it just allow for or have you made
the comparison?
CSB REPORTING
[phone]
646 TATUM (X)
Idaho Power Company
.
.
.
14
1 A Oh, I've made the comparison. I have an
2 exhibi t that actually compares the results. If you look
3 at Exhibit 69, Exhibit 69 shows the cost of service
4 resul ts for the base case study, the modified base case
5 study and the 3CP/12CP study and the comparison is made
6 on a percentage change basis for each customer class.
7 Q Well, are you saying that what you refer
8 to here as base case is the same as the methodology
9 that's in force now?
10 A I identified how it is different in my
11 direct testimony. There are a few factors that are
12 different in the derivation of the inputs. A number of
13 the changes resulted from the cost of service workshops
that occurred. following the '03 case. We've incorporated
15 a new methodology that we discussed earlier today that
16 resulted from and was recommended by the workshop
17 participants. There's also been a change related to the
18 derivation of the coincident peak demands to recognize
19 the impact of the Irrigation Peak Rewards Program, but
20 overall the methodology I would characterize as quite
21 similar other than those.
22 Q Well, what I asked you was whether you had
23 made a comparison between the methodology that is in
24 force now and the 3CP /12CP and the answer to that seems
25 to be no; isn't that right?
CSB REPORTING.
[phone]
647 TATUM (X)
Idaho Power Company
.
.
.
1
2
A It is not an exact comparison,no.
Q Would you say it's close enough to answer
the question that I have asked?
A Yes,I do.
Q Okay.Now,as you know,Dr.Goins has
recommended that the Company be directed to retain an
3
4
5
6
7 outside expert entity to deal with the questions, the
8 myriad of questions, that have been bantered about over
9 the years with regard to its cost studies. Would you
10 find any difficulty with the Commission directing the
11 Company to do that?
12 A No.
13 Q As you know, Dr. Goins has recommended
14 that the Commission direct the Company to do whatever
15 rate increases are ordered here on an across-the-board
16 basis until a more acceptable cost of service methodology
17 is developed. Would you find any difficulty with the
18 Commission directing the Company to do that?
19
20
A Yes, I would.
Q Now, assuming that the Commission decides
21 that it presently has no acceptable cost of service
22 methodology before it that it could use to allocate costs
23 among the ratepayer classes, is there any acceptable way
24 to do these rate increases except across the board?
25 A You're asking me if there's an acceptable
CSB REPORTING
[phone]
648 TATUM (X)
Idaho Power Company
.
.
1 way to determine the revenue requirement for each class
2 absent a cost of service study?
3 Q Absent a cost of service study that this
4 Commission finds acceptable, is there any way logically
5 to make rate increases at whatever level that are ordered
6 in this case, is there any way to do that other than
7 across the board?
8 A Well,I'm sure there's lots of ways,
yes.
Q What are they?
A What are they?
Q Yes.
A Well,I'm here to support my cost of
service study which I'm advocating should be the basis of
9
10
11
12
13
14
15 our determination of the revenue requirement for each
16 customer class and that the revenue requirement should be
17 determined based upon that study. I'm not prepared to
18 recommend a different methodology of determining the
19 revenue requirement.
20 Q Well, what we're talking about is not
21 determining the revenue requirement but determining the
22 allocation among the ratepayer classes. Now, what I'm
23 asking you is before this Commission or any commission
24 doing electric utility rates, if there is no cost of.25 service methodology that the Commission feels it can
CSB REPORTING
[phone]
649 TATUM (X)
Idaho Power Company
.
.
.
1 adopt, is there any way to make rate increases other than
2 across the board? That's logical given the situation.
3 A Okay. Well, I guess what I'm saying is
4 that goes outside the scope of my testimony here and it
5 would be a policy question for Mr. Gale.
6 Q Would you regard Dr. Goins' proposal to
7 classify costs as 57.1 percent demand and 42.9 percent
8 energy as a reasonable approach?
9 A I think I mention that in my rebuttal
10 testimony as I mentioned my support for the load factor
11 approach to classification and still support that
12 methodology; however, out of all the other proposals in
13 this case for al ternati ve classification methodology, I
14 thought, I still believe, that Mr. Goins' or Dr. Goins'
15 methodology is the most reasonable of any of the proposed
16 alternatives.
17 Q Okay. Now, would that go also for his
18 proposal to classify all purchased power 57.1 demand
19 related and 42.9 energy related?
20 A I would, I support the use of the same
21 classification methodology for purchased power as would
22 be used for the base load and generation plant
23 classification.
24
25
Q So if the Commission adopted Dr. Goins'
proposed 57 percent and 42 percent for steam and hydro,
CSB REPORTING
[phone]
650 TATUM (X)
Idaho Power Company
.
.
.
1 you testified that it should also do that with regard to
2 purchased power?
3 A I think that's consistent with the
4 approach that I'm recommending. If you're going to make
5 a change to the classification methodology for the
6 generation plant, base load and intermediate generation
7 plant, that you should make a consistent change to the
8 purchased power classification.
9 Q All right, Dr. Goins has also proposed
10 that the Commission reject the Company's proposed
11 assignment of all demand-related hydro plant costs to
12 base load and instead assign 50 percent of that to peak
13 and 50 percent to base load. Would you regard that as a
14 reasonable approach?
15 A Well, I understand his rationale, but I
16 disagree with. the proposal.
17 Q Well, you disagree with the proposal that
18 we talked about a moment ago, but you said it was the
19 best of the ones that you've rej ected and would you say
20 the same thing about this 50-50 proposal that I've
21 mentioned?
22 A The 50-50 proposal is to allocate is it
23 the hydro plant? Can you repeat your statement?
24
25
Q Sure. You all proposed to assign all
demand-related hydro plant costs to base load. Dr. Goins
CSB REPORTING
[phone]
651 TATUM (X)
Idaho Power Company
.
.
.
.
1 suggests 50 percent of this demand-related hydro plant to
2 base load and 50 percent to peak, that's his proposal.
3 Can you tell us whether you regard that as an acceptable
4 proposal? I understand you like your proposal better,
5 but would this one be as acceptable as the earlier
6 proposal we talked about?
7 A I don't know that. I can't speak to how
8 reasonable it is. I haven't evaluated the utilization of
9 our hydro plant to the extent that I could identify what
10 portion of the hydro should be peak related versus
11 non-peak related. I imagine that it's not 50-50,
12 though.
13 Q Okay, but you haven't assessed that
14 proposal?
15 A That I have assessed the proposal?
16 Q You have not assessed that proposal, that
17 is your testimony?
18 A I have not analyzed the reasonableness of
19 that proposal, no.
20 Q Okay, Dr. Goins also recommended that the
21 Company use a weighted 12CP rather than the non-weighted
22 12CP that you recommend --
23 MR. WALKER: I'm going to object to that
24 question. We've already been over that particular issue
25 several times tonight and this is getting argumentative.
CSB REPORTING
[phone]
652 TATUM (X)
Idaho Power Company
.
.
21
22
i i don't think we need to run Mr. Tatum through every
2 portion of Mr. Goins' recommendation. He's testified to
3 the proposal that he supports here and it's not
4 Mr. Goins'.
5 MR. BRUDER: Surely as an expert, as the
6 Company's expert, whose obligation it is to assess all
7 reasonable proposals, he must have assessed this and
8 surely, the Commission is entitled to his opinion if he
9 has one.
10 COMMISSIONER SMITH: Mr. Bruder, given the
11 hour, it might help if you could condense -- if there's
12 something more you need from him besides that Dr. Goins'
13 proposal was the best of the ones he rej ected
14 MR. BRUDER: I'll move on. I have one
15 more question and only one.
16 Q BY MR. BRUDER: Regarding off-system
17 sales, off-system sales are mostly produced in
18 non-summer, non-peak months because that's when the
19 excess steam and hydro capacity is available for sale
20 off-system; is that correct?
A Would you repeat your question, please?
Q Sure, let's look at off-system sales and
23 off-system sales revenues. Now, off-system sales are
24 mostly made and so off-system sales revenues are mostly.25 received for non-summer, non-peak months. The reason for
CSB REPORTING
[phone]
653 TATUM (X)
Idaho Power Company
.
.
1 that is that that is when the excess steam and hydro
2 capacity is available for sale off-system; is that
3 right?
4 A I can't confirm that. No, I don't know.
5 Are we still talking about in the test year or just in
6 general?
7 Q Well, I'm talking about methodology for
8 allocating off-system sales revenues as offsets to cost.
9 A I don't know. I can't confirm what you
10 just said.
11 MR. BRUDER: I have nothing further.
12 Thank you.
13 COMMISSIONER SMITH: Thank you. Mr.
14 Price, is there anything left to ask?
15 MR. PRICE: I just have a couple of pages
16 right here. I can get through it real quick. I have no
17 questions.
18 COMMISSIONER SMITH: Commissioner Redford?
19 COMMISSIONER REDFORD: I have no
20 questions.
21 COMMISSIONER SMITH: Do you have any
22 redirect?
23 MR. WALKER: Well, given the hour, Your
24 Honor, I don't think I have any redirect..25 COMMISSIONER SMITH: That was the right
CSB REPORTING
[phone]
654 TATUM (X)
Idaho Power Company
.
.
19
20
21
22
23
24
. 25
1 answer.
2 (The witness left the stand.)
3 COMMISSIONER SMITH: All right, we have a
4 public hearing that will commence at 7: 00 p.m., shortly.
5 I was going to suggest we start in the morning at
6 9:00 a.m. I think that ought to give us time, so we are
7 adjourned for now. We'll see you all at 9:00 a.m.
8 (The Hearing recessed at 6: 10 p.m.)
9
10
11
12
13
14
15
16
17
18
CSB REPORTING
[phone]
655 COLLOQUY