20110602Tatum Di, Exhibits.pdf

RECEIVED
101 l .Juri - l PM 2= 42
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
TO ITS CUSTOMERS IN THE STATE OF
IDAHO.
CASE NO. IPC-E-ll-08
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
TIMOTHY E. TATUM
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 (~Idaho
6 Power" or ~Company") as a Senior Manager of Cost of Service
7 in the Regulatory Affairs Department.
8 Q .Please describe your educational background.
9 A.I have earned a Bachelor of Business
10 Administration degree in Economics and Master of Business
11 Administration degree from Boise State Uni versi ty. I have
12 also attended electric utility ratemaking courses,
13 including ~Practical Skills for The Changing Electrical
14 Industry," a course offered through New Mexico State
15 University's Center for Public Utilities, ~ Introduction to
16 Rate Design and Cost of Service Concepts and Techniques"
17 presented by Electric Utili ties Consultants, Inc., and
18 Edison Electric Institute' s ~Electric Rates Advanced
19 Course. "
20 Q.Please describe your work experience with
21 Idaho Power.
22 A.I began my employment with Idaho Power in 1996
23 as a Customer Service Representative in the Company's
24 Customer Service Center where I handled customer phone
25 calls and other customer-related transactions. In 1999, I
TATUM, DI 1
Idaho Power Company
1 began working in the Customer Account Management Center
2 where I was responsible for customer account maintenance in
3 the area of billing and metering.
4 In June of 2003, after seven years in customer
5 service, I began working as an Economic Analyst on the
6 Energy Efficiency Team. As an Economic Analyst, I was
7 responsible for ensuring that the Demand-Side Management
8 (~DSM") expenditures were accounted for properly, preparing
9 and reporting DSM program costs and acti vi ties to
10 management and various external stakeholders, conducting
11 cost-benefit analyses of DSM programs, and providing DSM
12 analysis support for the Company's 2004 Integrated Resource
13 Plan (~IRP").
14 In August of 2004, I accepted a position as a
15 Regulatory Analyst in Regulatory Affairs. As a Regulatory
16 Analyst, I provided support for the Company's various
17 regulatory acti vi ties, including tariff administration,
18 regulatory ratemaking and compliance filings, and the
19 development of various pricing strategies and policies.
20 In August of 2006, I was promoted to Senior
21 Regulatory Analyst. As a Senior Regulatory Analyst, my
22 responsibilities expanded to include the development of
23 complex financial studies to determine revenue recovery and
24 pricing strategies, including the preparation of the
25 Company's cost-of-service studies.
TATUM, DI 2
Idaho Power Company
1 In September of 2008, I was promoted to Manager of
2 Cost of Service and in April of 2011 I was promoted to
3 Senior Manager of Cost of Service. As Senior Manager of
4 Cost of Service, I oversee the Company's cost-of-service
5 acti vi ties such as power supply modeling, jurisdictional
6 separation studies, class cost-of-service studies, and
7 marginal cost studies.
8 I. OVERVIEW
9 Q.What is the purpose of your testimony in this
10 proceeding?
11 A.The purpose of my testimony is to present the
12 forecast methodologies that were applied to the Company's
13 2010 financial data to arrive at the 2011 forecasted
14 financial levels. Further, my testimony will describe the
15 instructions that I provided to Mr. Matthew T. Larkin, Ms.
16 Kelley Noe, and Mr. Douglas N. Jones with regard to the
17 normalizing, annualizing, and other regulatory adj ustments
18 required to arrive at the 2011 test year revenue
19 requirement.
20 Q.Did you consult with Mr. Gregory W. Said, Vice
21 President of Regulatory Affairs, regarding the development
22 of the 2011 test year?
23 A.Yes. The 2011 test year development
24 methodology presented in the remainder of my testimony is a
25 direct result of numerous discussions with Mr. Said.
TATUM, DI 3
Idaho Power Company
1 Q.Did Mr. Said provide you with any specific
2 instructions or guidance regarding the development of the
3 test year presented in this proceeding?
4 A.Yes. Mr. Said instructed me to develop a 2011
5 test year based upon 2010 actual financial data in a manner
6 similar to that approved by the Idaho Public Utilities
7 Commission (~Commission") in the Company's last general
8 rate case, IPC-E-08-10 (~2008 Rate Case"), Order Nos. 30722
9 and 30754. However, Mr. Said instructed me to deviate from
10 the methodology used in the 2008 Rate Case in a number of
11 specific areas. First, Mr. Said instructed me to hold
12 operations and maintenance (~O&M") expenses to 2010 levels
13 with the exception of specific cost categories that are
14 ~known" to be materially different in 2011. Second, Mr.
15 Said instructed me to hold normalized total power supply
16 expenses and other Power Cost Adjustment (~PCA") accounts
1 7 to 2010 levels approved by Order No. 31042 with adjustments
18 to recognize revenues from Hoku Materials, Inc. (~Hoku")
19 and projected demand response incentive payments. Third,
20 Mr. Said asked that the level of recovery of Allowance for
21 Funds Used During Construction (~AFUDC") associated with
22 the Hells Canyon relicensing proj ect construction work in
23 progress (~CWIP") not be increased above the level approved
24 in the Company's 2008 Rate Case. Each of Mr. Said's
25 instructions to deviate from the methodology used in the
TATUM, DI 4
Idaho Power Company
1 2008 Rate Case has the effect of reducing the Company's
2 revenue requirement request in this case.
3 Mr. Said also directed me to set the 2011 test year
4 pension expense at $17.2 million, the level currently
5 approved for recovery in Case No. IPC-E-11-04, Order No.
6 32248.
7 Q.Will you briefly summarize how the Company has
8 developed its 2011 test year (~2011 Test Year" or ~Test
9 Year")?
10 A.Yes. The development of the 2011 Test Year
11 began with 2010 actual financial data (~2010 Actuals") .
12 2010 Actuals were adjusted by Mr. Jones to reflect
13 traditional ratemaking adjustments and to arrive at 2010
14 adjusted actual financial information (~2010 Base"). The
15 2010 Base was then adjusted to reach 2011 forecasted
16 financial levels (~2011 Unadjusted Test Year"). Finally,
17 annualizing adjustments were made to the 2011 Unadjusted
18 Test Year to reach the Company's 2011 Test Year.
19 II. DEVELOPMNT OF THE 2011 UNADJUSTED TEST YEA
20 Q. Please describe the forecast methodologies
21 used to adjust the 2010 Base to the 2011 Unadjusted Test
22 Year.
23 A.There were two primary methods developed and
24 applied to the 2010 Base Year to forecast the 2011
25 Unadjusted Test Year. First, the Company used the
TATUM, DI 5
Idaho Power Company
1 unchanged 2010 Base Year financial data when the Company
2 believed that certain amounts would continue to remain at
3 2010 levels or if account balances were very small.
4 Alternatively, ~Other Adj ustments" were applied based upon
5 known or probable factors for 2011 that relate to a
6 particular account. Examples of these factors include, but
7 are not limited to, new billing and volume contract terms,
8 discontinued services, anticipated levels of economic
9 activity, and existing regulatory commission orders.
10 Q .How does the forecast methodology used in this
11 case differ from that applied in the 2008 Rate Case?
12 A.Aside from the specific adj ustments requested
13 by Mr. Said mentioned earlier in my testimony, the maj or
14 difference between the forecasting methodology used in this
15 case and that applied in the 2008 Rate Case is the
16 utilization of growth rates to escalate O&M expenses. In
17 the 2008 Rate Case, the Company applied Compound Annual
18 Growth Rates (~CAGRs") to adj ust a number of O&M expense
19 accounts. Based on historical data, CAGRs represented a
20 steady level of positive or negative growth from the
21 beginning period to the ending period. To develop the 2011
22 Test Year, the Company has not applied any escalation
23 factors to forecast O&M expenses. Instead the Company has
24 made a conscious choice to hold test year O&M expenses to
25 2010 Base levels with adjustments only to specific cost
TATUM, DI 6
Idaho Power Company
1 categories that are ~known" to be materially different in
2 2011.
3 Q.Have you prepared exhibits that list all
4 accounts and identify the specific method you used to
5 forecast the 2011 Unadjusted Test Year?
6 A.Yes. I directed the preparation of Exhibit
7 No. 19 to present a summarized list of all accounts to
8 which the two previously discussed methods were applied.
9 Each of the methodologies is described in more detail
10 within the Forecast Methodology Manual, Exhibit No. 20,
11 which was also prepared at my direction. To develop the
12 Forecast Methodology Manual, the Company performed a review
13 of each group of accounts included wi thin the test year.
14 Based upon specific knowledge and analysis of that account
15 grouping, the Company either used 2010 Actuals or applied
16 an Other Adjustment methodology to that account to
17 represent an appropriate level of anticipated spending.
18 Q.Have the data and the associated adjustments
19 made to your exhibits and supporting schedules been
20 calculated on a total system basis?
21 A.Yes. Ms. Noe will address the determination
22 of the Idaho jurisdictional test year values in her
23 testimony.
24 Q.Please identify the maj or areas or groupings
25 of financial accounts addressed by the methodologies
TATUM, DI 7
Idaho Power Company
1 included in the Forecast Methodology Manual (Exhibit No.
2 20) .
3 A.The maj or areas or groupings of financial
4 accounts addressed in Exhibit No. 20 include Other
5 Operating Revenues (Accounts 451, 454, and 456), Operation
6 and Maintenance Expenses (Accounts 500 through 900),
7 Depreciation and Amortization Expense (Accounts 403 and
8 404), and Electric Plant in Service (~EPIS") (Account 101).
9 A detailed discussion of the individual accounts and
10 methods used is provided in Exhibit No. 20.
11 Q.Please provide an overview of the methodology
12 used to forecast 2011 Other Operating Revenues (Accounts
13 447, 451, 454, and 456).
14 A.Consistent with Mr. Said' s directive, Surplus
15 Sales Revenues (Account 447) were held to the currently
16 approved 2010 normalized levels. The remaining Other
17 Operating Revenues (Accounts 451, 454, and 456) were
18 forecasted to be the same as 2010 actual revenue with the
19 exception of four revenue categories: 1) cogeneration and
20 small power production revenues, 2) facilities charge
21 revenues, 3) network services and other long term firm and
22 point-to-point transmission revenues, and 4)Sierra
23 Pacific Power Company sales.
24 Cogeneration and small power production revenues
25 were determined by adjusting the 2010 revenues to account
TATUM, DI 8
Idaho Power Company
1 for 13 new wind proj ects that have or will come on-line in
2 2011. Facilities charge revenues were determined by
3 adjusting the 2010 actual revenues to account for a reduced
4 facili ties charge rate as proposed by Mr. Scott Sparks in
5 his testimony in this case. Network services and other
6 long term firm and point-to-point transmission revenues
7 were proj ected based upon information more reflective of
8 current circumstances and an anticipated Open Access
9 Transmission Tariff rate update in October 2011. Finally,
10 Sierra Pacific Power usage revenues were adj usted to zero
11 to recognize that no usage revenues from Sierra Pacific
12 Power are expected in 2011.
13 A detailed discussion of the methods applied to
14 determine Other Operating Revenues for the 2011 Unadjusted
15 Test Year is provided on pages 8-10 of Exhibit No. 20.
16 Q.Please provide an overview of the methodology
17 used to forecast 2011 Operation and Maintenance Expenses
18 (Accounts 500 through 900).
19 A.Based upon the instructions I received from
20 Mr. Said, the PCA expense accounts were held to the
21 currently approved 2010 normalized levels with adjustments
22 to recognize normalized revenues from Hoku and projected
23 base level demand response incentive payments, which I will
24 describe in greater detail later in my testimony. The PCA
25 expense accounts include Fuel Expense (Accounts 501 and
TATUM, DI 9
Idaho Power Company
1 547), Water for Power Expense (Account 536.002), Purchased
2 Power Expense (Account 555 - excluding purchased power for
3 transmission losses), and Transmission of Electricity by
4 Others (Account 565).
5 The remaining O&M adj ustments were also made in
6 accordance with Mr. Said's instructions. The Idaho Energy
7 Efficiency Rider Expense (Account 908) was removed in its
8 entirety from the 2011 Test Year. Incenti ve Expense
9 (Account 920) was forecasted for 2011 to include only the
10 normalized incentive components that are attributable to
11 Customer Satisfaction and Reliability, consistent with the
12 method approved in the 2008 Rate Case, Order No. 30722.
13 Incentive expense represents the ~at-risk" portion of
14 employees' total compensation package. Pension Expense
15 (Account 926) for the ~daho jurisdiction was held to the
16 level approved by the Commission in Case No. IPC-E-11-04,
17 Order No. 32248. Regulatory Commission Expenses (Account
18 928) were adjusted to include known changes in
19 amortizations for recovery of Commission-ordered intervenor
20 funding. The remaining O&M expense amounts were segregated
21 into labor and non-labor expense groupings to determine the
22 respective 2011 forecast amounts.
23 Q.Please provide an overview of the methodology
24 used to forecast 2011 O&M labor expense.
25
TATUM, DI 10
Idaho Power Company
1 A.The 2011 labor expense was forecasted by
2 applying historical monthly labor cost relationships to the
3 first two calendar months of 2011 actual labor costs. More
4 specifically, the 2011 O&M labor forecast was developed by
5 first calculating the three-year historical average of
6 February year-to-date actual O&M labor costs as a
7 percentage of the total year actual O&M labor costs. The
8 resulting percentage was determined to be 15.00 percent.
9 This percentage was then applied to the actual February
10 2011 year-to-date O&M labor to estimate the total 2011 O&M
11 labor costs. The February amount was first reduced by
12 pension expense and by the Smart Grid related O&M labor,
13 which acts as a credit offset in a non-labor cost element.
14 The resulting 2011 labor projection of $133.9 million was
15 then allocated to the applicable Federal Energy Regulatory
16 Commission (~FERC") accounts based on 2010 actual labor
1 7 charges to those same accounts. This method is similar to
18 that utilized by the Commission Staff in the 2008 Rate Case
19 to validate the Company's labor forecast as additional
20 actual labor cost data became available throughout the test
21 period. A more detailed discussion of the labor-related
22 O&M adjustment is provided in Exhibit No. 20, pages 10 and
23 11.
24 Q.Please provide an overview of the forecast
25 methodology used to forecast 2011 non-labor O&M expenses.
TATUM, DI 11
Idaho Power Company
1 A.The 2011 non-labor O&M expenses, excluding the
2 accounts mentioned above, were projected to be equal to the
3 2010 actual expense level with adjustments only for
4 significant known changes. At my direction, the O&M
5 expenses were reviewed by subj ect matter experts to
6 identify and adj ust those areas, based on specific
7 knowledge, where expense levels are expected to be
8 materially different than those included in the 2010 Base.
9 The review identified significant specific increases or
10 decreases to the 2010 non-labor actual levels in the
11 following categories:
12 · ThermalO&M Increases Identified by Operating
13 Partners
14 · Bennett Mountain - Combustor Inspection
15 · Commission Ordered Amortizations
16 · Smart Grid Investment Grant Credit in 2010 - Not
17 Recurring
18 · North American Electric Reliability Corporation
19 Required Light Data and Ranging Surveys
20 · Bureau of Land Management Rate Increase - Land
21 Rents
22 · Idaho Fish and Game's Projected Hatchery Expense
23 Increases
24 · Increased IT Maintenance Expenses
25 · Specific Reliability Proj ects - Transmission
TATUM, DI 12
Idaho Power Company
1 Actual 2010 non-labor O&M, excluding the items
2 identified previously, equaled $142.3 million. Following
3 the adjustments for significant known changes, non-labor
4 O&M is projected to increase by $15.6 million to $157.9
5 million. A more detailed discussion of the non-labor O&M
6 adjustments is provided in Exhibit No. 20, pages 11-15.
7 Q.Please provide an overview of the methodology
8 to forecast 2011 Depreciation and Amortization Expense
9 (Accounts 403 and 404) .
10 A.The 2011 depreciation expense, amortization
11 expense, and related reserve accounts were calculated based
12 on the monthly estimated 2011 plant balances. Depreciation
13 rates authorized by Commission Order No. 30639 were used
14 for the entire 2011 Test Year. The determination of the
15 Depreciation and Amortization Expense adjustments is
16 detailed in Exhibit No. 20, page 23.
17 Q.Please provide an overview of the methodology
18 to forecast 2011 Electric Plant in Service (Account 101).
19 A.Electric Plant in Service is a function of
20 multiple components, including actual year-end 2010 EPIS
21 and CWIP balances, estimated 2011 spending, expected 2011
22 closings of CWIP, and estimated retirements. Therefore, it
23 was necessary to use a number of methodologies to develop
24 the 2011 Unadjusted Test Year EPIS balances, which are
25 detailed in Exhibit No. 20, pages 28-29.
TATUM, DI 13
Idaho Power Company
1 To project 2011 construction expenditures and 2011
2 closings of CWIP to EPIS, at Mr. Said's instruction, the
3 Company first bifurcated into two separate and distinct
4 parts, those proj ects in excess of $2 million and those
5 under $2 million.
6 Proj ects in excess of $2 million were reviewed by
7 the individual proj ect managers, who estimated the costs to
8 complete and the in-service date of each proj ect. The
9 investment in proj ects under $2 million (excluding
10 vehicles) closing to EPIS as a group, were forecasted to be
11 comparable to actual 2010 closings to EPIS when determining
12 the 2011 Unadjusted Test Year. This method is based upon
13 an assumption that construction activities in 2011 are not
14 anticipated to exceed, but rather keep pace with 2010
15 levels.
16 Q.Please provide an overview of the methodology
17 to forecast 2011 AFUDC associated with Hells Canyon
18 relicensing CWIP.
19 A.While AFUDC continues to increase relating to
20 the Hells Canyon relicensing efforts, the Company is
21 requesting recovery of the same amount ($6,815,472)
22 previously included in the 2008 Rate Case and subsequently
23 approved in Order No. 30722. This adjustment is explained
24 in greater detail in Exhibit No. 20, page 27.
25
TATUM, DI 14
Idaho Power Company
1
2
3
4
III. ANALIZING & OTHER ADJUSTMNTS
TO ARIVE AT THE 2011 TEST YEA
Q. In Mr. Jones's testimony, he describes the
5 various adjustments that were made to 2010 Actuals to
6 arrive at the 2011 Base Year. Do these same adjustments
7 need to be made in 2011?
8 A.No. These adj ustments are standard ratemaking
9 adjustments based on prior Commission orders and are
10 adjustments to charges included in the 2010 Actuals. By
11 removing them from 2010 Actuals prior to applying the
12 various methodologies to arrive at the Company's proposed
13 2011 Unadjusted Test Year, the same adjustments are already
14 accounted for.
15 Q.What were your instructions to Mr. Larkin with
16 regard to the determination of the test year retail sales
17 revenues (Account 442)?
18 A.I instructed Mr. Larkin to determine the 2011
19 Test Year retail sales revenues using the same methodology
20 approved by the Commission in the 2008 Rate Case, Order No.
21 30722. That is, my instructions were to develop the test
22 year retail sales revenues based upon forecasted billing
23 determinants under normal weather and precipitation
24 assumptions. As Mr. Larkin will cover in greater detail in
25 his testimony, the 2011 test year billing determinants were
26 developed based upon the Company's energy sales and
TATUM, DI 15
Idaho Power Company
1 customer count forecasts prepared for the 2011 IRP. To
2 derive the demand-related billing determinants, historical
3 demand-to-energy relationships were applied to the energy
4 sales forecast. The forecasted billing determinants were
5 then applied to the rates in effect at the time of the
6 filing to determine the 2011 Test Year retail sales
7 revenues.
8 Q.Are there any additional adjustments that need
9 to be made to properly reflect the 2011 Test Year?
10 A.Yes. It is necessary for the Company to make
11 additional annualizing and known and measureable
12 adj ustments.
13 Q.Please describe the additional annualizing
14 adjustments made under your direction to the 2011 Test
15 Year.
16 A.I instructed Ms. Noe to make annualizing
17 adjustments to certain expense and rate base items to
18 reflect them as though they have been in existence for the
19 entire Test Year; that is, at year-end 2011 levels. These
20 include operating payroll, 2012 salary structure
21 adjustment, depreciation expense and reserve, and plant
22 placed in service during 2011 in excess of $2 million with
23 the associated estimated property taxes and insurance
24 premiums. Such adjustments are appropriate to reflect
25 conditions that will be in effect at the time rates are
TATUM, DI 16
Idaho Power Company
1 placed in effect. Ms. Noe provides additional detail
2 regarding the annualizing adjustments in her testimony.
3 Q.Did you have any additional instructions for
4 Ms. Noe?
5 A.Yes. As mentioned earlier in my testimony,
6 Mr. Said directed me to hold the PCA expense accounts to
7 the currently approved 2010 normalized levels with
8 adjustments to recognize normalized revenues from Hoku and
9 proj ected base level demand response incentive payments.
10 Consistent with this directive, I developed the adjusted
11 2010 PCA components shown on Exhibit No. 21. As can be
12 seen on Exhibit No. 21, each of the PCA components is
13 consistent with the currently approved 2010 amount with the
14 exception of Account 442, Hoku First Block Energy Revenues;
15 Account 555, PURPA; and Account 555, Demand Response
16 Incentives. The adj usted PCA expense amounts shown in
17 column ~D" of Exhibit No. 21 were provided to Ms. Noe for
18 use in the Idaho jurisdictional revenue requirement
19 determination.
20 Q.Upon what basis did you make adjustments to
21 Account 442, Hoku First Block Energy Revenues and Account
22 555, PURPA?
23 A.Because the 2010 PCA components did not
24 include Hoku First Block Energy Revenues , it was necessary
25 to make an adjustment to increase the PCA-related revenues
TATUM, DI 17
Idaho Power Company
1 by $23.9 million in the 2011 Test Year. To not include
2 Hoku First Block Energy Revenues in the 2011 Test Year
3 would improperly understate the Company's expected retail
4 sales revenue. However, to hold the sum of the PCA
5 components to no change as directed by Mr. Said, an
6 offsetting expense adj ustment was necessary. Based on a
7 review of the 2011 normalized PCA components developed by
8 Mr. Wright, it was clear that an offsetting adjustment
9 could be justified for PURPA expenses, which Mr. Wright has
10 testified would increase by $50.4 million in 2011.
11 Therefore, Account 555, PURPA was increased by $23.9
12 million.
13 Q.How was the adjustment to Account 555, Demand
14 Response Incentives, determined?
15 A.Under my direction, a forecast for Account
16 555, Demand Response Incentives, was developed based upon
17 proj ected fixed incentive levels for the AC Cool Credit,
18 FlexPeak Management, and Irrigation Peak Rewards programs
19 on an Idaho jurisdictional basis. The proj ected incentive
20 levels for these programs were determined using currently
21 approved fixed incentive amounts and expected participation
22 levels for each program. Because the forecasted amounts
23 were Idaho jurisdictional proj ections, I instructed Ms. Noe
24 to directly assign them to the Idaho jurisdiction.
25
TATUM, DI 18
Idaho Power Company
1 Q.Has an exhibit been prepared that details each
2 of the adjustments that were made to move from the 2010
3 Actuals to the 2011 Test Year?
4 A.Yes. Ms. Noe's Exhibit No. 25 summarizes the
5 adj ustments that were made to each FERC Account to: 1)
6 move from the 2010 Actuals to the 2010 Base, 2) move from
7 the 2010 Base to the 2011 Unadjusted Test Year, and 3) move
8 from the 2011 Unadjusted Test Year to the 2011 Test Year.
9 Q.According to Ms. Noe's analysis using the 2011
10 Test Year financial information, what is the Company's
11 revenue requirement on a system-wide and Idaho
12 jurisdictional basis?
13 A.Using the 2011 Test Year financial
14 information, Ms. Noe has calculated the Company's revenue
15 requirement to be $965.2 million on a system-wide basis and
16 $ 917.6 million on an Idaho jurisdictional basis. Ms. Noe
17 calculated the Company's annual revenue deficiency, the
18 amount that the test year revenue requirement exceeds the
19 test year retail sales revenue, to be $90.6 million on a
20 system-wide basis, and $82.6 million on an Idaho
21 jurisdictional basis. An increase to annual Idaho
22 jurisdictional revenues in the amount of $82.6 million
23 would result in an overall average increase to customer
24 rates of 9.9 percent.
25
TATUM, DI 19
Idaho Power Company
1 Q.Is it appropriate for the Commission to
2 determine the Company's Idaho jurisdictional revenue
3 requirement to be $917.6 million, its revenue deficiency to
4 be $82.6 million, and therefore, approve an overall 9.9
5 percent increase to customer rates?
6 A.Yes. The $917.6 million figure is a
7 reasonable determination of the Company's annual Idaho
8 jurisdictional revenue requirement. The $82.6 million
9 quantification of revenue deficiency is also reasonable.
10 It is in the best interest of the Company and its customers
11 for the Commission to approve a rate increase to provide a
12 9.9 percent increase to the Company's Idaho jurisdictional
13 revenues.
14 Q.Does this conclude your direct testimony in
15 this case?
16 A.Yes, it does.
17
18
19
20
21
22
23
24
25
TATUM, DI 20
Idaho Power Company
BEFORE THE
RECEIVED
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IDAHO PUBLIC UTiliTIES COMMYSSr6Nfl¡;'~1
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
TATUM, 01
TESTIMONY
EXHIBIT NO. 19
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BEFORE THE
RECEIVED
ZO!! JUN -I PM 2: 44
tD\HO
IDAHO PUBLIC UTILITIES COMMISS¡o~iS
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
TATUM, 01
TESTIMONY
EXHIBIT NO. 20
HIDA~PO.
An IOACORP copany
Forecast Methodology Manual
2011 Rate Case
Proprietary I! 2011 Idaho Power
Exhibit No. 20
Case No. IPC-E-11-08
T. Tatum, IPC
Page 1 of 35
Idaho Power Company Forecast Methodology Manual
TABLE OF CONTENTS
Table of Contents............................................ ................................................................................. i
Cross-Reference List of Tables.............................................. ........................................................ iv
Introduction......................................................................................................................................1
Forecast Methods .............................................................................................................................2
Cost Of Service Components...........................................................................................................3
Forecast Adjustment A-other Operating Revenues................................................................3
Description....... ............... ........... ............ ... .... ........ ...............................................................3
Forecast Methodology .........................................................................................................3
Forecast Adjustment B & C-other Revenues and Other Expenses ........................................5
Description...................... ........... ................................. .., ......................................................5
Forecast Methodology .........................................................................................................5
Forecast Adjustment D-erations and Maintenance Expenses ("O&M")............................5
Overview..............................................................................................................................5
Labor ..................................................................................................................................5
Non-Labor............................................................................................................................6
FERC Account Development................ ............... ........................ ........... ........... ...............10
Exceptions to the Described O&M Methodology Above ........ ..........................................11
Steam Power Generation....................................................................................................12
Description. ........ .............................. .... ............. .......... ........................ ................... ... ...12
Forecast Methodology .................................................................................................12
Hydraulic Power Generation..............................................................................................12
Description... ..................... .... ....... ..................... ....................................... .............. ..... .12
Forecast Methodology .................................................................................................13
Other Power Generation ........... ............ ............. ....... .............................. ..................... ..... .13
Description............ ................ .... .......................... .... ............... ..................................... .13
Forecast Methodology .................................................................................................13
Transmission Expenses..................................................................................................... .14
Proprietary Pa~ibit No. 20
Case No. IPC-E-11-08
T. Tatum, IPC
Page 2 of 35
Forecast Methodology Manual Idaho Power Company
Description ..... ............. .~............. ............................ ..... ........................ ....................... .14
Forecast Methodology .................................................................................................14
Distrbution Expenses..... ..................... ......................................... .... ....... ........ ........... ..... ..15
Description........................................... ....... ....................... ........... ......................... ..... .15
Forecast Methodology............................... .................. ....................................... ....... ..15
Customer Accounting and Customer Services and Information Expenses.................... ...15
Description.................. .................. .... ....... ........... ......... .......... ..... ...... ....... ........ .... ...... ..15
Forecast Methodology .................................................................................................15
Administration and General Expenses ("A&G").. ........ ....... ... ...... .............. .............. .... .....16
Description........................................................ .......... .......... ....................... ...... ...... ....16
Forecast Methodology....................................... .... ........................ ....... ...... ................ .16
Forecast Adjustment E-Depreciation and Amortization Expense.........................................18
Description................ .............. ................. ............. ............................................. ............... .18
Forecast Methodology .......................................................................................................18
Forecast Adjustment F-E1ectrc Plant/Regulatory Assets-Amortization,
Adjustments, Gains and Losses.................. ................................................. .......... ....... ..18
Description.................................................... .................................... .................. ..... ......... .18
Forecast Methodology .......................................................................................................19
Forecast Adjustment G-Regu1atory Debits and Credits... ..................................... ...... ........ ..19
Description............................................................. .......................... ..... ......... ................... .19
Forecast Methodology .......................................................................................................19
Forecast Adjustment H- Taxes Other than Income Taxes .....................................................20
Description.................. ....................... ........... .............. ........................ ...... ............. ........... .20
Forecast Methodology ...............................................................................:.......................20
Real and Personal Propert Taxes ...............................................................................20
Idaho kWh Taxes ............ ........................................................ .....................................20
Regulatory Commission Fees ....................................................................................~.20
Licenses ...............................................................;.......................................................21
Franchises ....................................................................................................................21
Page ii ProprieWIi¥bit No. 20
Case NO.IPC-E-11-08
T. Tatum, IPC
Page 3 of 35
Idaho Power Company Forecast Methodology Manual
Forecast Adjustment I-Idaho Energy Resources Co. ("IERCO") Cost of Service
Components ....................................................................................................................21
Description.................... .......... .................. ............................... ........... ........... ............... .... .21
Forecast Methodology .......................................................................................................21
Forecast Adjustment J-Allowance for Funds Used During Construction ("AFUDC")
Related to Hells Canyon Relicensing...............................................................................22
Description.............................................. .......................................................................... .22
Forecast Methodology .......................................................................................................22
Rate Base Components............... ............... ................................................................................... .23
Forecast Adjustment K-Electrc Plant in Service..................................................................23
Description... .............................................. ........................ ............... ....... ......................... .23
Forecast Methodology .......................................................................................................23
Plant Additions to Electrc Plant In Service.... ........ ............. .... ..... ........ .......................... ..23
Projected 2011 Plant Additions .......... .... .... ...................... ....... .... ...... .................... .... ..23
Allocation to FERC Plant Account............ ........ ...................... ...... .............................24
Retirements from Electrc Plant In Service .................... .................................. .................24
Forecast Adjustments L & M-Accumulated Provision for Depreciation and
Amortization........................................................................ .......................................... .25
Description.. ..... .......................................................... ..................... ...... ........... ................. .25
Forecast Methodology .......................................................................................................25
Forecast Adjustment N-Materials and Supplies....................................................................26
Description............................................................ .............................. ........... .......... ......... .26
Forecast Methodology .......................................................................................................26
Forecast Adjustment ü-ther Deferred Programs................................................................27
Description..... ........................................................... .................................................... .... .27
Forecast Methodology .......................................................................................................27
Forecast Adjustment P-Plant Held for Futue Use................................................................28
Description.................. ...... ............................................................ ................. ................... .28
Forecast Methodology .......................................................................................................28
Forecast Adjustment Q-ustomer Advances for Construction ("CAC") .............................28
Proprietary Pag~x"ibit No. 20
Case NO.IPC-E-11-08
T. Tatum, IPC
Page 4 of 35
Forecast Methodology Manual Idaho Power Company
Description. ...................... .................................................................... ...... ...... ........... ...... .28
Forecast Methodology .......................................................................................................29
Forecast Adjustment R-Idaho Energy Resources Co. ("IERCO") Rate Base.......................29
Description............... ................................. ................ ......... .... .........;... ..... ........ ......... ........ .29
Forecast Methodology .......................................................................................................30
CRoss-REFERENCE LIST OF TABLES
Provided in Ms. Noe's Exhibits
Table 4-FERC Accounts 451-456 .......... ...................................................................................3
Tables 4&5-FERC Accounts 415-416 (excluding 415.002 and 416.002)...............~.................5
Table 5-FERC Accounts 500-935 .. ...... ....... ..............................................................................5
Table 6-FERC Accounts 403 and 404......................................................................................18
Table 6-FERC Accounts 406, 411.6, and 411. 7 .......................................................................18
Table 8-FERC Account 407.3 ..................................................................................................19
Table 7-FERC Account 408.1 ..................................................................................................20
FERC Accounts 418.1 and 419............................................... ............. .................................. .....21
FERC Accounts 107 ............... ....................................... ..............................................................22
Table 1-FERC Account 101.....................................................................................................23
Table 2-FERC Accounts 108 and 111................................................................................ ......25
Table 3-FERC Accounts 154 and 163............. .............................. .................................. .........26
Table 3-FERC Accounts 182.3 and 186...................................................................................27
Table 3-FERC Account 105 ................................ .....................................................................28
Table 3-FERC Account 252 ........................................... ..........................................................28
Table 3-FERC Accounts 123.1, 186, and 145..........................................................................29
Page iv Proprie~ifbit No. 20
Case No. IPC-E-11-08
T. Tatum, IPC
Page 5 of 35
Idaho Power Company Forecast Methodology Manual
INTRODUCTION
This Forecast Methodology Manual ("Manual") was developed solely to provide supporting
information for the methodologies that Idaho Power Company used to set the values contained in
its proposed 2011 test year in Case No. IPC-E-11-08 before the Idaho Public Utilities
Commission ("IPUC"). The financial forecasts, estimates, and other information contained
herein were developed solely for ratemakg puroses. This Manual should not be relied upon
by current or prospective investors or securties market professionals for any purose.
These values were provided to IPC witness Noe for appropriate application to the Uniform
System of Accounts for determination of revenue requirement in the 2011 test year. The manual
is organzed in thee sections and includes:
. Forecast Methods. Forecast Methods includes a description of the forecast
methodologies used to develop the 2011 unadjusted test year from the 2010 actul
financial data.
. Cost of Service Components. Cost of Service Components includes a description of
the thee digit account number specified in the Uniform System of Accounts adopted by
the Commission and the FERC and the forecast method for each major account or
account group.
. Rate Base Components. Rate Base Components includes a description of the three digit
account number specified in the Uniform System of Accounts adopted by the
Commission and the FERC and the forecast method applied for each major account or
account group.
Proprietary Pa9fx~ibit No. 20
Case No. IPC-E-11-08
T. Tatum, IPC
Page 6 of 35
Forecast Methodology Manual Idaho Power Company
FORECAST METHODS
Updates to the 2010 actual financial data to IPC's proposed 2011 unadjusted test year were
developed using one of the following two forecast methods:
(1) 2010 Base. 2010 actual fmancial data was used when the IPC believed that certin
amounts would continue to remain at 2010 levels or if account balances were very smalL.
(2) Other Adjustments. Other Adjustments are based on known or probable factors for
2011 that relate to a paricular account. Examples of these factors include but are not
limited to new billing and volume contrct terms, discontinued services, anticipated
levels of economic activity, and existing regulatory commission orders.
Page 2 Proprie~~bit No. 20
Case No. IPC-E-11-08
T. Tatum, IPC
Page 7 of 35
Idaho Power Company Forecast Methodology Manual
COST OF SERVICE COMPONENTS
Forecast Adjustment A-Other Operating Revenues
Table 4-FERC Accounts 451-456
Description
Account 451 includes revenues for all miscellaneous services and charges biled to customers
that are not specifically provided for in other accounts. This includes fees for changing,
connecting, or disconnecting services and profit on maintenance or installations on customers'
premises. Miscellaneous service revenues include continuous service reversion charges (Idaho
only), field visit charges, retu trp charges, retued check fees, service connection charges,
service establishment charges, and application and processing fees collected for new permits,
new leases, or requests for easement relinquishments. Account 454 includes rents received for
the use by others of land, buildings, and other propert devoted to electrc operations by IPC
such as joint pole attachments, facilities charges, and line and substation rents. Account 456
includes revenues derived from electrc operations not includable in other revenue accounts. For
example, compensation for mior serices provided for others, such as engineerig and revenues
from transmission of electrcity of others over trsmission facilities of IPC, such as network and
point-to-point wheeling.
Forecast Methodology
Forecast Adjustment A increases Other Operating Revenue (Accounts 451-456) by $1,653,959
above the 2010 Base. Accounts 451 though 456 used a combination of the methods for
projecting 2011 amounts as described below.
Account 451-MIscellaneous Service Revenues. These revenues were projected for 2011 to be
the same as the 12 months actual ended December 2010 Base. Ths method was used because
revenues in ths category are not expected to either decrease or increase materially beyond the
2010 leveL.
Account 454-Rent from Electric Property. Rents from Electrc Propert were projected
based on either the twelve months actul ended December 2010 balance or the Other Adjustment
methodology.
Substation equipment rentals, trsformer and distrbution rentals, station and line rentals, real
estate rents, dak fiber rents, joint pole attchments, overnght park rents were forecasted to be
the same as the 2010 Base, as this was the most reasonable expectation for these revenues.
Cogeneration and small power production revenues and facilities charge revenues were
determined by using the Other Adjustment methodology. The 2010 Base was increased for
thrteen new wind projects that have or wil come on-line in 2011. For 2011, cogeneration and
small power production revenues were calculated by taking the number of identified wind
projects ties the historical average annual revenue per wind project and then increased by an
anual historical growt rate of 4.5%. All existing cogeneration and small power production
Proprietary Pa9txMbit No. 20
Case No. IPC-E-11-08
T. Tatum, IPC
Page 8 of 35
Forecast Methodology Manual Idaho Power Company
revenues (Schedule 72 only) were also increased by 4.5% for annual historical growt.
This resulted in a forecast adjustment for $ 1 97,439 for cogeneration and small power production
revenues. For facilities charge revenues, IPC reviews the rate for these charges intermittently.
Durig a recent review, IPC determined that the rate should be decreased based on the curent
methodology. For 2011, the new anual rate wil decrease the revenues generated from the
facilities charges by $1,137,825.
Account 456-0ther Electric Revenues. Other Electrc Revenues were projected based using
either the car-forward of the 2010 Base or the Other Adjustment methodology based on known
factors of the individual tye of2011 revenues to be projected as described below:
Revenues related to the photovoltaic station service, Antelope substation, Sierr stand-by service,
and miscellaneous were projected for 2011 to be the same as the 2010 Base, as this was the most
reasonable expectation for these revenues.
The 2011 Network Transmission Customer revenues were calculated based on nie month of
the network trnsmission customers' average load ratio share times the formula-based FERC
transmission revenue requirement in effect from October 1, 2010, though September 30,2011,
and thee months of the network trsmission customers' average load ratio share times the
forecasted FERC trnsmission revenue requiement. The timing for the Transmission Revenue
Requirement is the same as the point-to-point wheeling rate described below. The 2011
estimated network customer MW demand used to calculate the Network Transmission Customer
revenue was calculated by taing 2009 MW demand and escalating it using the .7% anual
growt factor assumed in the 2009 IR for 2010. The escalated 2010 MW demand was then
increased by 2 MW for new network customer MW demand in 2011
The 20 1 1 point-to-point ("PTP") wheeling revenues were forecasted based on the Other
Adjustment methodology and were calculated based on nie months of the 2011 equivalent
KWhs times the formula basedFERC transmission rate, effective October 1,2010, through
September 30, 2011, and thee months of the 2011 equivalent KWhs ties the forecasted
transmission rate. The three-quarers and one-quarter year revenue calculation split uses the
known curent transmission rate is in effect though September 30,2011, and forecastig a rate
that would be in effect October 1, 2011 for the final thee months. The 2011 equivalent KWhs
are based on an average of 2009 and 2010 equivalent KWhs.
Sierra Pacific Power Usage revenues were forecasted based on the Other Adjustment
methodology. For 201 l, Valmy usage is not expected to exceed capacity; therefore no revenues
from Sierr Pacific Power Usage are expected.
Page 4 ProprieWIibit No. 20
Case No. IPC-E-11-08
T. Tatum, IPC
Page 9 of 35
Idaho Power Company Forecast Methodology Manual
Forecast Adjustment B & C-Other Revenues and
Other Expenses
Tables 4&5-FERC Accounts 415-16 (excluding 415.002 and 416.002)
Description
Accounts 415 though 416 respectively, include all revenues derived from the sale of
merchandise and jobbing or contract work and all expenses incured in such activities. For IPC,
jobbing and contract work revenues and expenses include activities related to Idaho Power
Solutions, water management services, and joint pole use.
Forecast Methodology
Forecast Adjustments Band C for Other Revenues (Account 415) and Other Expenses (Account
416), respectively are both $0, therefore the 2011 forecast remains the same as the 2010 Base.
Actul account 415 and account 416 results have not seen signficant growt or decline over the
last two years. Revenues and expenses in these accounts are typically close to equa and
offsetting. Therefore, any fluctuations in these accounts from year to year have little or no impact
on the revenue requirement.
Forecast Adjustment D-Operations and Maintenance
Expenses ("O&M")
Table 5-FERC Accounts 500-935
Overview
Forecast Adjustment D increases Operations and Maintenance Expenses ("O&M")
(Accounts 500-935) by $41,565,914 above the 2010 Base. Excluded from Adjustment Dis
any increase in normalized accounts 501-Fuel, 547-Fuel, 555-Purchased Power.
In developing the 2011 forecast, IPC split O&M historical actuals into two elements (Labor and
Non-Labor) and forecasted each element separately and then allocated each separtely to the
individual FERC accounts. Excluded from ths process were accounts 555.050 (Purchased Power
Transmission Losses), 565.000 (Trasmission of Electrcity by Others), 908.131, 908.132 (Idaho
and Oregon Energy Effciency Riders), 920.001 (Incentive), 926.203, 926.204, and 926.205
(Pension Expense), and 928.203 and 928.303 (Regulatory Commission Expenses), as these were
handled separately
Labor
IPC calculated the projected 2011 O&M labor by first calculating the average thee-year
historical Februar year-to-date actual O&M labor costs. as a percentage of the total year actul
O&M labor costs which was determined to be 15.00%. This percentage was then applied to the
Proprietary Pa9fx~bit No. 20
Case No. IPC-E-11-08
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Page 10 of 35
Forecast Methodology Manual Idaho Power Company
actual Februar 2011 year-to-date O&M labor of$20,083,335 to estimate the total 2011 O&M
labor costs of$133,886,252 (the February amount was first reduced by pension expense accounts
926.203,204 and 205), and by the Smart Grid related O&M labor (cost centers 305 and 888)
which has a credit offset in a non-labor cost element. The 2011 labor projection was then
allocated to FERC account based on 2010 actual labor charges to those same accounts.
The table below details the 201 1 estimated labor amount:
2011 Labor Expenses
February Y-T-D O&M Labor Excluding Incentive & Pension
Divided by the Historical February Y-T-D as a Percentage of Total Year Labor
2011 O&M Labor Expense Excluding Incentive and Pension
Total
$20,083,335
15.00%
$133,886,252
Non-Labor
IPC calculated the projected 2011 non-labor O&M expenses by holding to 2010 non-payroll
actul expenses with adjustments for signficant known changes. IPC reviewed the O&M
expenses to identify and adjust those areas, based on specific knowledge, where expected
expense levels are expected to be materially different than those included in the 2010 actuals.
The table below identifies signficant specific increases or decreases to the 2010
non-labor actual:
2011 O&M Non-Labor Expenses Total Allocated Direct Assignment
2010 O&M Non-Labor Actuals $142,271,408 $0 $142,271,408
2011 Identified Significant Known Adjustments
Thermal O&M Increases from Operating Partners 6,708,356 6,708,356
Bennett Mountain-2011 Combustor Inspection 1,257,722 1,257,722
Commission Ordered Amortizations (1,466,130)(1,466,130)
Smart Grid Investment Grant ("SGIG") Credit in 2010 4,437,427 4,437,427
Not Recurring
NERC Required L1DAR Surveys 1,414,000 1,414,000
BLM Rate Increase-Land Rents 841,224 841,224
Idaho Fish and Game's Projected Hatchery Increases 731,856 731,856
Increased IT Maintenance Expenses 723,200 723,200
Special Reliabilty Projects-Transmission 950,000 950,000
Inflation and Growth Related Increases
Subtotal 2011 Identified Significant Known Adjustments 15,597,655 4,437,427 11,160,228
Total 2011 O&M Non-Payroll Expenses $157,869,063 $4,437,427 $153,431,636
Page 6 Proprie~x!jbit No. 20
Case No. IPC-E-11-08
T. Tatum, IPC
Page 11 of35
Idaho Power Company Forecast Methodology Manual
The following adjustment to the 2010 Base included in the table above have been allocated to
FERC account balances rather than directly assigned:
. SGIG credit in 2010 not recurring--&M work relating to Smart Grid in 2010 was
reduced by federal governent reimbursements. The positions previously occupied by
those involved with SGIG were largely left unfilled when those individuals began
workig on the Smar Grid project. In the latter par of 20 1 0 and in 2011, those
unoccupied positions wil or have been filled so the reduction to overall O&M that was
generated by the 2010 credit wil not reoccur in 2011.
The following adjustments to the 2010 Base included in the table above have been directly
assigned to one or more FERC accounts:
. Power Supply Thermal (Excluding Fuel)-2010 actul thermal plant O&M was
increased by $6,708,356 due to the following:
. Valmy Power Plant-Non-fuel O&M expenses at the Valmy Plant for 2011 is
expected to increase by approximately 11 % over 2010 levels. The increases are due to
rising chemical costs and usage; higher propert insurce, legal, and environmental
costs; and higher general admnistrative overheads. These increases are parially
offset by lower maintenance costs associated with the major unt outage. Major
maintenance is done on each of the two Vàly unts every thee years. Unit 2 was
overhauled in 2010, while unt 1 wil be overhauled in 2011. Unit 2 has a scrubber
and therefore incur the majority of the chemical costs at the plant. Chemical
expenses were lower in 2010 because ths unt was offine for major maintenance for
nine weeks. To offset ths increase for 2011, overall maintenance expenses in 2011
are expected to be down as the duration of the major unt overhaul on Unit 1 will be
shorter and the scope of repair work is expected to be less than Unit 2. Adminstrtive
and general overheads are expected to be higher in 2011 due to an increase in plant
O&M expenses and retroactive credits recorded in 2010 that will not re-occur in
2011. IPC negotiates an adminstrtive and general ("A&G") rate for Valmy that is
applied to actul plant O&M expenses. Periodically Valmy A&G expenses that get
allocated to IPC by use of this rate are "tred-up" to actul costs. NY Energy issued
IPC credits in 2010 because actul 2009 and a portion of actul 20 i 0 A&G expenses
were less than what was charged out though the A&G rate. A fixed Valmy A&G rate
was negotiated in 2010 that wil car though mid-year 2012. No prior period tre-up
credits or charges are expected to occur in 2011.
. Bridger Power Plant-u&M labor costs in 2011 at the Jim Bridger Plant are
expected to increase 12.5% compared to 2010 levels. The increase is attbuted to
PacifiCorp's wage escalation and enanced 401K benefits per Union Contract Local
127 that was renegotiated in 2010. In addition, a reduction in capital spending at the
Jim Bridger plant is expected to result in additional labor dollars being allocated to
O&M as compared to 2010.
O&M expenses attrbuted to materials are expected to increase 9.4%, compared to
2010 levels. The increase is priarly due to chemicals used to treat mine water being
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diverted to the plant for use in the cooling towers, as well as additional materials
planng to be consumed or installed as part of the maintenance overhaul on Unit #3.
O&M expenses attbuted to outside services are expected to increase 22.4%,
compared to 2010 levels. A reduction in capital spending at the Jim Bridger plant is
expected to result in additional services being allocated to O&M that could not be
charged to capital as done in 2010. Examples include boiler scaffolding expenses of
approximately $ 1 milion that was charged to the low NOx burer capital project in
2010, but wil be classified as O&M ths year and turbine bearig work related to the
2010 tubine upgrade project.
Neither the impairent cost incurred in 2010 related to the delay and likely
cancelation of the tubine upgrade projects nor the reduction from a prior year accrul
tre-up are expected to recur in 2011.
· Boardman Power Plan-Non-fuel O&M expenses at the Boardman plant are
expected to increase 24% or $840,000 from 2010 levels. The increase is attbuted to
additional additives and chemicals that wil result from the installation of Mercur
and NOx retrofits planned to be in-service by mid-20l1, as well as an increase in
overall plant maintenance. The pollution control retrofits at Boardman in 2011. are
being installed to comply with the Oregon Utility Mercur Rule to reduce
mercur emissions, and comply with federal regional haze (RH BART) rules for
NOx reductions.
The Boardman plant experienced an outstanding year in 2010, with a forced outage
factor (sum of all hours experienced durg forced outages divided by number of
hours the unit was in an active state) of2.4% compared to an 2009 forced outage rate
of 5.4%. This was due to fewer forced outages, specifically tube leaks, as compared
to recent years. This, combined with fewer problems and issues being discovered
durng the major maintenance outage, caused 2010 overall maintenance expenses to
be less than what the plant has experienced in recent year. The increase in plant
maintenance expenses expected in 2011 is priarly the result of using historical
trendig to build the forecast, rather than simply relying on the 2010 result.
While the increases above were diectly assigned to the overall Power Supply
Thermal (Excluding Fuel) accounts, these increases were then allocated to FERC
accounts 500-515 (excluding 501) based on 2010 actuls amounts in those
same accounts.
· Bennett Mountain Combustor Inspection-Account 554 was increased by $1,257,722
above 2010 Base due to a scheduled periodic combustor inspection and combustor pars
refubishment at the Bennett Mountain Power Plant. An inspection was not performed
in 2010.
· Commission Ordered Amortizations-The following amortizations resulted in a
decrease to the 2010 Base by $1,466,130.
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Account 908 was reduced by $1,621,331 due to the non-recurg DSMlConservation
(IPUC Order No. 27660) amortization that was completed in June 2010.
Account 928 was increased $155,201 due to 2011 having thee fewer months of the credit
amortization of the FERC OFA refund (IPUC Order No. 30722 and 30791). This
amortization is completed in August 2011.
. NERC Required LIDAR Surveys-Account 563 was increased by $1,414,000 due to
the need to perform LIDAR Sureys (Light Detection and Rangig) to verify
transmission line ratig values and methodology in order to satisfy the NERC Alert
issued in October 2010.
. BLM Rate Increase for Land Rents-Accounts 567, 589, 931 and 935 increased
$841,224 over the 2010 Base rents due to new Federal rent schedules and Zone schedule
changes. These rents are for IPC lines and facilities that are located on BLM lands.
Five FERC accounts were increased based on 2010 actuals as follows-account 935 was
increased by $4,070; account 921 was increased by $128,026; account 931 was increased
$12,173; account 589 was increased $135,786; and account 567 was increased by
$561,169.
. Idaho Fish & Game's Projected Hatchery Increases-Account 537 was increased
above 2010 Base by $731,856 due to a projected increase from Idaho Departent ofFish
& Game (IDFG) for hatcher operations. The increase is related to a number of factors
including expanded harvest monitoriglatchery perormance evaluation, increased
personnel, O&M and overhead costs, development of a fish identification system, and a
contrbution toward a region-wide hatchery data base.
. Increased IT Maintenance Expenses-Account 921 was increased by $723,200 due to
softare and hardware maintenance increases. SGIG projects hardware and softare
maintenance (after the product's first year) is not reimbursed by the government.
This amount is incremental since IPC will stil be operating on the legacy mainframe
systems until the new hardware and softare is fully tested and promoted into
production. The expected in-service date is the second quaer of 20 13 for the new
applications. At that time, IPC wil be archiving data from the legacy systems and
beging the process to discontinue maintenance on these legacy systems. IPC has also
included an incremental amount for storage and monitorig tools due to an increase in
data storage required on an anual basis and the increase in new open systems that
require monitorig tools.
. Special Reliabilty Projects-Transmission, account 563, was increased by $950,000 for
transmission projects that are above the normal level of trmission maintenance that
was performed in 2010. The projects will repair or replace guy wires on the Bridger to
Goshen Trasmission Line, and replace dead-ends on the Oxbow to Pallette Junction
Transmission Line.
Once O&M labor and non-labor increase or decrease amounts were determined for each FERC
account, the results were combined to reflect the total forecast adjustment.
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FERC Account Development
Since IPC does not forecast by individual FERC accounts the following two methods (Direct
Assignent and Allocation) were used to assign both labor and non-labor to the appropriate
FERC accounts.
Direct Assignment Method-The forecast adjustments listed in the direct assignent colum in
the non-labor expenses above are charges that would occur in specific accounts and therefore
were directly assigned to those accounts listed below.
. Account 500-5l5-Thermal Plant O&M
. Account 537-Idaho Fish & Game's Projected Hatchery Increases
. Account 554-Bennett Mountain Combustor Inspection
. Account 563-NERC Required LIDAR Surveys; Trasmission Reliability Projects
. Account 567-a porton of the BLM Rate Increase
. Account 589-a porton of the BLM Rate Increase
. Account 908-Non-recurg DSM Amortization
· Account 92l-IT Maintenance Expenses; a portion of the BLM Rate Increase
· Account 928-Non-recurg Amortization ofFERC OFA Refud
· Account 93l-a portion of the BLM Rate Increase
. Account 935-a portion of the BLM Rate Increase
Allocation Method-This method was used to allocate the forecast amounts when the
identification of specific accounts was impossible or when the impact would be to all accounts.
The O&M labor forecast was allocated to individual FERC accounts based on the percentage of
20 1 0 actual O&M labor charges incured withi each account to total O&M labor charges
incured in 2010. The O&M non-labor forecast (not directly assigned) was allocated based on
2010 actual non-labor charges included in each FERC account to total O&M non-labor charges
incured in 2010.
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Exceptions to the Described O&M Methodology Above
FERC Accounts 555.050, 565.000, 908.131, 908.132, 920.001, 926.203, 926.204, 926.205,
928.202, 928.203, and 928.303
As stated earlier, the following were forecasted separtely from the labor and non-labor O&M
forecast described above and directly assigned to the FERC accounts they impact:
· Account 501-Fuel Expense. This account is trditionally forecasted using the
AURORAxmpQ! ModeL. However, for ths test year, IPC has included the Base level
established in 2010.
. Account 547-Fuel Expense (Excluding 547.000-Salmon Diesel). This account is
normally forecasted for the test year using the AURORAxmpQ! ModeL. However, for the
test year, IPC has elected to include, as its 2011 forecast, the previously approved 2010
Base level per IPUC Order No. 31042.
. Account 555-Purchased Power (Excluding 555.050). This account is forecasted for
the test year using the AURORAxmpQ! ModeL. However, for the test year, IPC has elected
to include, as its 2011 forecast, the previously approved 2010 Base level per IPUC Order
No. 31042 with the exception of adjustments as described in testimony.
. Account 555.050-Purchased Power Transmission Losses. This account is anticipated
to increase above the 2010 Base by $359,462.
· Account 557-other Expense (Excluding 557.000). The amounts in these accounts
have been removed in their entirety from the test year.
. Account 565.000- Transmission of Electricity by Others. For the test year, IPC has
elected to include, as its 2011 forecast, the previously approved 2010 Base level per
IPUC Order No. 31042.
. Account 908.131 and 908.132-Idaho and Oregon Energy Effciency Rider
Expenses. The amounts in these accounts have been removed from the 2010 Base in their
entirety per the IPUC Order No. 30189.
. Account 920.001-Incentive Expense. The entire actual 2010 incentive expense of
$16,398,839 was removed from the 2010 Base and replaced with the projected 2011
incentive of $6,680,748 that includes only elements related to Customer Satisfaction and
Reliability. This resulted in a net reduction for incentive expense of$9,718,091.
· Accounts 926.203, 926.204 and 926.205-Pension Expense. Pension expense
amortization was increased in the Idaho jursdiction by $13,993,913, the FERC
jursdiction by $129,964 and in the Oregon jursdiction by $8,788.
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. Accounts 928.203 and 928.303-Regulatory Commission Expense. Intervenor
Funding was estimated to increase $160,478 by assuming a one-year amortization period,
per the following Orders:
. IPUC Order No. 30978-eAP AI for $4,379.
. IPUC Order Nos. 30722-eAPAI for $11,464 and IIPA for $38,472.
. IPUC Order Nos. 30892-eAPAI for $10,510, ICL for $9,854 and IIPA for $20,677.
. OPUC Order No. 11-011-eUB 2011 Funding Grant for $32,350.
. OPUC Order No. 10-406-eUB 2010 Funding Grant for $32,772.
The following O&M discussion has been organized by functional account groups. With each
account group, a general description of the accounts has been provided.
Steam Power Generation
FERC Accounts 500-514
Description
Accounts 500 though 514 include the labor, materials, and expenses incured to operate and
maintain prie movers, generators, and their auxiliary apparatus, switch gear, and other electrc
equipment used in steam power generation. Additionally, the labor and expenses incured in the
general supervision and direction of maintenance of steam generation facilities are included in
these accounts.
Forecast Methodology
Accounts 500-5l4-Excluding Account 501, Fuel Expense. The 2011 projection for accounts
500-514 was developed by adjusting the 2010 Base with the identified increases provided to IPC
from the operating parers of the Thermal Generating Plants. The identified increases were
spread to accounts 500-515 (excluding 501) based on 2010 actul amounts in those same
accounts.
Account SOl-Fuel Expense. Fuel expense is normally forecasted for the test year using the
AURORAxmpiI ModeL. However, for the test year, IPC has elected to include, as its 2011
forecast, the previously approved 2010 Base level per IPUC Order No. 31042.
Hydraulic Power Generation
FERC Accounts 535-545
Description
Accounts 535 though 545 include the labor, materials used, and expenses incured to operate
and maintain hydrulic works including strctues, reservoirs, dams, waterways, generators,
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roads and bndges, and expenses directly related to the hydroelectrc development outside the
generating station, including fish and wildlife and recreational facilities. These accounts also
include the labor and expenses incured in the generl supervision and direction of maintenace
of hydraulic power generating stations, rents of propert of other used, occupied, or operated in
connection with hydrulic power generation, including amounts payable to the United States for
the occupancy of public lands and reserations for reservoir, das, flumes, forebays, penstocks,
and power houses.
Forecast Methodology
Accounts 535-545- The projection of accounts 535-545 was developed using both methods
descnbed under FERC Account Development above. For labor, these accounts received their
allocated portion of the total 2011 labor projection based on actual 2010 labor. For non-labor,
these accounts were projected to be equal to the 2010 Base adjusted by the increase in account
537 for Idaho Fish & Game's projected hatchery increases of$731,856 and by each account's
allocated portion of the $4,437,427 non-direct adjustment to non-labor O&M.
Other Power Generation
FERC Accounts 546-557
Description
Accounts 546 though 554 include the operation labor, matenals used, and expenses incured in
operating and maintaining prue movers, generators, and electrc equipment in other power
generating stations. Labor and expenses incured in the general supervision and direction of
maintenance of other power generating stations are also included in these accounts. Account 556
includes labor and expenses incured in load dispatchig activities for system control. System
control activities include the production and dispatching of electrcity. Account 557 includes
production expenses incured directly in connection with the purchase of electrcity which is not
specifically provided for in other production expense accounts.
Forecast Methodology
Accounts 546-557-Excluding Account 547, Fuel Expense; Account 555, Purchased Power;
and Account 557, Other Expense. The projection of accounts 546-557 was developed using
both methods descnbed under FERC Account Development above. For labor, these accounts
received their allocated portion of the total 2011 labor projection based on actul 2010 labor.
For non-labor, these accounts were projected to be equal to the 2010 Base and adjusted by a
$1,257,722 increase (in account 554) for the 2011 Bennett Mountain Combustor Inspection, and
by each account's allocated portion of the $4,437,427 non-direct adjustment to non-labor O&M.
Account 547-Fuel Expense and Account 555-Purchased Power (Excluding 555.050).
Fuel and purchased power is normally forecasted for the test year using the AURORAxmpiI
ModeL. However, for the test year, IPC has elected to include, as its 2011 forecast, the previously
approved 2010 Base level per IPUC Order No. 31042 with the exception of adjustments to
Purchased Power as descnbed in testimony.
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Account 555.050-Purchases Power Transmission Losses. This account is projected to
increase above the 2010 Base by $359,462. Purchased Power Transmission losses were
developed based upon projected volumes and market prices.
Account 557, Other Expense (Excluding 557.00o-0ther Power Production Expense).
These expenses are removed entirely from the test year.
Transmission Expenses
FERC Accounts 560-573
Description
Accounts 560 through 573 include the operation labor, materials used, and expenses incured in
the system planng, operation, executing the reliability coordination fuction, monitoring,
assessing, and operating the power system and individual trsmission facilities in real-time to
maintain safe and reliable operation of the transmission system specified. Additional activities
include: processing the hourly, daily, weekly, and monthy transmission service requests using
an automated system such as an Open Access Same-Time Information System ("OASIS");
biling to transmission owners for system control and dispatchig service; and conducting
transmission services studies for proposed tranmission interconnections and generation
interconnection with the trsmission system. These accounts include the labor, materials used,
and expenses incured in the operation of transmission substations, switchig stations, and
transmission lines. The use of trsmission facilities owned by others and rents of property used,
occupied, or operated in connection with the transmission system are also par of this account.
The accounts also include the labor, materials used, and expenses incurred in the maintenance of
strctues, computer hardware and softare, communcation equipment, miscellaneous
trsmission plant, station equipment, and transmission plant serving the transmission fuction.
Forecast Methodology
Accounts 560-573-Excluding Account 565.000, Transmission of Electricity by Others
(3rd.Party Transmission). The projection of accounts 560-573 was developed using both
methods described under FERC Account Development above. For labor, these accounts received
their allocated portion of the total 201 1 labor projection based on actual 2010 labor.
For non-labor, these accounts were projected to be equal to the 2010 Base adjusted by
$1,414,000 increase for the LIDAR Surveys, and $950,000 increase for Transmission Reliability
Projects both to account 563, a $561,169 increase in account 567 for its portion of the BLM rate
increase for land rents, and by each account's allocated portion of the $4,437,427 non-direct
adjustment to non-labor O&M.
· Account 565- Transmission of Electricity by Others. This account was estimated to
increase above the 2010 Base by $2,343,493. For the test year, IPC has elected to include,
as its 2011 forecast, the previously approved 2010 Base level per IPUC Order No. 31042.
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Distribution Expenses
FERC Accounts 580-598
Description
Accounts 580 though 598 include labor, materials used, and expenses incured in the general
supervision and direction of the operation of the distrbution system such as station operation,
overhead and underground line operation, meter deparent operation of customer meters and
associated equipment, load dispatchig operations, work on customer installations,
and inspecting premises. Also included in these accounts are the labor, materials used, and
expenses incured in the general supervision and direction of the maintenance of the distrbution
system, including maintenance of strctues, distrbution plant, overhead distrbution line
facilities, underground distrbution line facilities, distrbution line transformers, meters,
and meter testing equipment.
Forecast Methodology
Accounts 580-598. The projection of accounts 580-598 was developed using both methods
described under FERC Account Development above. For labor, accounts 586 and 597 (operation
and maintenance of distrbution meters) were held equal to the 2010 Base and assuming that,
with the new AMI meter, expenses would not increase in 2011. All other accounts received their
allocated portion of the tota12011 labor projection based on actul 2010 labor. For non-labor,
these accounts were projected to be equal to the 2010 Base adjusted by $135,786 in account 589
for its portion of the BLM rate increase for land rents, and by each account's allocated portion of
the $4,437,427 non-direct adjustment to non-labor O&M.
Customer Accounting and Customer Services
and Information Expenses
FERC Accounts 901-905 and 907-912
Description
Accounts 901 though 905 include the labor, materials used, and expenses incured in the general
direction and supervision of customer accounting and collecting activities, including reading
customer meters, work on customer applications, contracts, orders, credit investigations,
biling and accounting, collections, and complaints. These accounts also include the accounting
for losses from uncollectible utility revenues. Accounts 907 though 912 include the labor and
expenses incured in customer service and informational activities to encourge safe and effcient
use of the utility's service, to encourage conservation of the utility's service, and answer specific
inquiries as to proper use of the service and equipment utilizing the service.
Forecast Methodology
Accounts 901-905 and 907-912-Excluding Account 908.131 and 908.132, Idaho and
Oregon Energy Efficiency Rider. The projection of accounts 901-905 and 907-912,
excluding the Idaho and Oregon Energy Effciency Rider (energy effciency expenses), was
developed using both methods described under FERC Account Development above. For labor,
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these accounts receìved theìr allocated portìon of the total 2011 labor projectìon based on
actual 2010 labor. Additìonally, account 902 was reduced by $1,973,938 accounting for the
savìngs attbutable to AMI. For non-labor, these accounts were projected to be equa to the
2010 Base and by each account's allocated portìon of the $4,437,427 non-drrect adjustment to
non-labor O&M.
Account 908.131 and 908.132-Idaho and Oregon Energy Efficiency Rider. The expenses
assocìated wìth the Idaho and Oregon Energy Effcìency Rìders have been exc1uded from the
2011 test year ìn therr entìrety (IPUC Order No. 30189).
Administration and General Expenses (tlA&G'?
FERC Accounts 920-935
Description
Accounts 920 though 935 ìnc1ude activìtìes undertaken ìn connection wìth the utìlìty's general
and admìnstrtive operations that are assìgnable to specìfic admìnstrtive or general
deparents and are not specìfically provìded for ìn other accounts. A&G accounts ìnc1ude:
(1) compensatìon of officers, executives, and other employees of the utilìty whìch are properly
chargeable to utilìty operatìons but not chargeable drrectly to a parìcular operating fuctìon,
(2) office supplìes and expenses, (3) fees and expenses ofprofessìonal consultats and others for
general servìces whìch are not applìcable to a parcular operatìng fuction, (4) ìnsurance or
reserve accruals to protect the utì1ìty agaìnst losses and damages to owned or leased property
used ìn ìts utì1ty operatìons, (5) payments for employee accìdent, sìckness, hospìtal, and death
benefits or ìnsurance, (6) payments to muncìpal or other governental authorities, (7) the cost
of materials, supplìes, and servìces fumìshed to such authoritìes wìthout reìmbursement ìn
complìance wìth franchìse, ordìnance, or sìmìlar requrrements, (8) expenses ìncured by the
utìlìty ìn connection wìth formal cases before regulatory commìssìons or other regulatory bodìes,
(9) regulatory fees assessed agaìnst the utìlìty, (10) commìssìon expenses, (11) payments made
to the Unìted States for the admìnìstration of the Federal Power Act, (12) materials used and
expenses ìncurred ìn advertìsìng and related actìvìtìes, (13) rents properly ìnc1udable ìn operatìng
expenses for the property of others used, occupìed, or operated ìn connectìon wìth customer
accounts, customer servìce, and ìnformatìonal sales and general and admìnstrative fuctìons of
the utìlìty, and (14) operatìon and maìntenance oftrsporttìon equìpment and the maìntenance
ofutìlìty property whìch ìs not chargeable drrectly to a parìcular operatìng fuctìon.
Forecast Methodology
Accounts 920-935-Excluding Account 920.001, Incentive Expense, 926.203, 926.204,
926.205, Pension Expense and part of 928.202, 928.203, and 928.303, Regulatory
Commission Expenses. The projectìon of accounts 920-935, exc1udìng ìncentive, was
developed usìng both methods described under FERC Account Development above. For labor,
these accounts receìved theìr allocated portìon of the total 2011 labor projection based on actual
2010 labor. For non-labor, these accounts were projected to be equal to the 2010 Base adjusted
upward by $155,201 ìn non-recurrng amortìzatìon ofthe FERC OFA refud ìn account 928,
and by $128,026, $12,173 and $4,070 ìncrease ìn accounts 921, 931 and 935, respectìvely for
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their portion of the BLM rate increase for land rent. These accounts also received each account's
allocated portion of the $4,437,427 non-direct adjustment to non-labor O&M.
Account 920.001-Incentive Expense. In the 2008 Idaho General Rate case order (IPUC Order
No. 30722) the Commission directed IPC to only include a normalized incentive that "is directly
related to improving service or reducing costs to customers." IPC therefore, included in its
projection only the normalized level of incentive attbutable to Customer Satisfaction and
Reliability. As a result, for the 2011 test year, IPC removed its entire 2010 actul incentive
expense of$16,398,839 from its 2010 Base and replaced that amount with its projected 2011
normalized incentive of $6,680,748 tht includes only those elements related to Customer
Satisfaction and Reliability. This resulted in a net reduction for incentive expense of$9,718,091.
Accounts 926.203, 926.204, and 926.205-Pension Expense. For the Oregon jurisdiction the
IPC's actury (Miliman) provided a total 2011 net periodic pension expense estimate (SFAS 87)
of$27,954,213 of which Oregon's allocated portion is $893,024. This is an $8,788 increase over
the amount included in the 2010 Base.
In the Idao jursdiction, per IPUC Order No. 31091, IPC is curently recovering $5,416,796 of
its cash contrbutions to its defied benefit pension plan over a one-year period that began in
June 2010. As a result of ths Order, included in the 2010 Base is seven months of amortization
expense for $3,159,800. IPC is including in its forecast the additional five months of
amortization for $2,256,996. In addition, IPC has requested in Case No. IPC-E-11-04 recovery of
an additional $11,736,917 for cash contrbutions made in 2010 which is also included in the
forecast, briging the total requested recovery amount for the Idaho jursdictional cash payments
to $17,153,713. Therefore, IPC has included in its forecast adjustment an additional $13,993,913
in amortization expense for 2011.
Since the FERC jursdiction follows the Idaho jursdiction for treatment of its portion of pension
expense (cash basis), IPC has included an additional $129,964 in amortzation in its estimate
above the existing $60,986 that is included in the 2010 Base.
Account 928-Regulatory Commission Expenses. This account was increased by $155,201
due to three months fewer amortization periods for the amortization of the reimbursement of
FERC OFA (IPUC Order No. 30722) than what was in 2010 actuals. This account was also
increased for intervenor fuding by $ 1 60,478 that was directed in IPUC Order Nos. 30978,
30722 and 30892 for $4,379, $49,936, $41,041, respectively and OPUC Order Nos. 11-011 and
10-406 for $32,350 and $32.772, respectively. IPC has assumed a one year amortization for
intervenor funding. Account 928 also received its allocated portion of the $4,437,427 non-direct
adjustment to non-labor O&M.
Accounts 908.131 and 908.132-Idaho and Oregon Energy Effciency Rider Expenses.
The amounts in these accounts have been removed from the test year in their entirety per IPUC
Order No. 30189.
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Forecast Adjustment E-Depreciation and
Amortization Expense
Table 6-FERC Accounts 403 and 404
Description
Account 403 includes depreciation expense for all classes of depreciable electrc plant in service
except such depreciation expense as is chargeable to clearg accounts or to account 416, Costs
and Expenses of Merchandising, Jobbing and Contract Work. Account 404 includes amortzation
charges applicable to amounts included in the electrc plant accounts for limited-term frchises,
licenses, patent rights, limited-term interest in land, and expenditues on leased propert where
the serice life of the improvements is terminable by action of the lease. The charges to ths
account are such as to distribute the book cost of each investment as evenly as may be over the
period of its benefit to the utility.
Forecast Methødology
Forecast Adjustment E increases Depreciation and Amortization Expense (accounts 403 and
404) by $4,974,317 above the 2010 Base
Depreciation and amortization rates were applied to the montWy estimated plant balances
(see the Electrc Plant in Service discussion in the Rate Base Components section).
The depreciation rates authorized by IPUC Order No. 30639 were used for the entire 2011 test
year. Several FERC plant accounts have sub-accounts, for which the individual sub-account data
was used to calculate a composite rate and applied at the major account leveL.
For plant accounts 392, Transporttion Equipment; 396, Power Operated Equipment; 312,
Boiler Plant Equipment; and 397, Communcation Equipment, either all or par of the
depreciation expense is recorded to other accounts and not account 403. The account 312,
Boiler Plant Equipment, and account 397, Communcation Equipment, depreciation amounts
were calculated using the actual 312.300 and 397.300 accrual for December 2010.
Forecast Adjustment F-Electric Plant/Regulatory Assets-
Amortization, Adjustments, Gains and Losses
Table 6-FERC Accounts 406. 411.6, and 411.7
Description
Account 406 is debited or credited, as the case may be, with amounts includable in operatig
expenses, pursuat to approval or order of the Commission, for the purose of providing for the
extinguishment of the amount in account 114, Electrc Plant Acquisition Adjustments. Accounts
411.6 and 411.7 includes, as approved by the Commission, amounts relatig to gains and losses
from the disposition of futue use utility plant, including amounts which were previously
recorded in and trsferred from account 105, Electrc Plant Held for Futue Use.
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Forecast Methodology
Forecast Adjustment F is $0, resulting in the Amortization of Electrc Plant Acquisition
Adjustments (account 406) and Gains and Losses from Disposition of Utility Plant
(account 411.6 and 411.7) remainng the same as the 2010 Base.
Account 406 is projected for 2011 to remain the same as the 2010 Base. Included in this account
is the amortization of the Praire Power acquisition adjustment of account 114 over 233 months
at $1,894 per month. The amount in account 114 wil be fully amortzed in July 2012.
Accounts 411.6 and 411.7 do not have a forecast since there is no plan to sell utility plant
in 2011.
Forecast Adjustment G-Regulatory Debits and Credits
Table 8-FERC Account 407.3
Description
Account 407.3 is debited, when appropriate, with the amounts credited to account 254,
Other Regulatory Liabilities, to record regulatory liabilities imposed on the utility by the
ratemakig actions of regulatory agencies. Ths account is also debited, when appropriate,
with the amounts credited to account 182.3, Other Regulatory Assets, concurent with the
recovery of such amounts in rates.
Forecast Methodology
Forecast Adjustment G increases Regulatory Debits (account 407.3) by $5,802 above the
2010 Base.
IPC has recorded a regulatory asset in account 182.339 for the "capitalized" portion of the net
periodic pension costs since August 2007. This capitalized portion is comprised of the Oregon
jursdictional share of net periodic pension cost for each year multiplied by that year's
capitalization percentage, which is determined based on an analysis of the year's labor costs to
determine the percentage of those costs that were ultimately recorded to constrction.
The capitalization percentage for 2010 was approximately 30.57 percent, which is the assumed
percentage for 2011 and 2012. IPC projects a balance for the Oregon capitalized pension costs of
$1,323,161 by December 31,2011. As a result of the capitalized balance, IPC has estimated the
amortzation of this amount in account 407.3 to be $27,757 for 2011, an increase of$5,802 over
the 2010 Base.
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Forecast Methodology Manual Idaho Power Company
Forecast Adjustment H- Taxes Other than Income Taxes
Table 7-FERC Account 408.1
Description
Account 408.1 includes those taxes other than income taxes which relate to utility operating
income. This account is maintained so as to allow ready identification of the varous classes of
taxes relatig to utility operation, plant leased to others, and other operating income.
Forecast Methodology
Forecast Adjustment H increases Taxes Other Than Income (Accounts 408.1) by $3,454,070
above the 2010 Base.
The 2011 forecast methodology for Taxes Other Than Income Taxes was based on a
combination of known adjustments arising from specifics of the particular account activity and a
carr forward of the 2010 Base amounts.
Real and Personal Propert Taxes
The Idao property taxes were $10.9 milion, $12.6 milion, and $14.9 milion in 2008,2009 and
2010, respectively. The propert tax increases can be attbutable to the increase in market value
determined by the Idaho Tax Commission (a result from an increase in utility plant investment
along with an increase in net operating income), an increase in local taxing distrcts budget
requirements and a shift in tax burden (residential home values decling).
The methodology used to project propert taxes for the 2011 test year is the same estimation
process used for establishing the anual propert tax accrual for IPC financial statements.
Propert taxes are estiated using both an appraisal and levy methodology. For the appraisal
methodology, actul appraisal data is used to the extent known and each state's historical
appraisal methodologies and trends are used in determing the appraisal amount. For the tax
levy methodology, the state's historical levy data and local governent budget policy is used to
estimate levies.
Idaho kWh Taxes
Test year 2011 kWh taxes were projected based on normalized hydro conditions and normalized
consumption.
Regulatory Commission Fees
The 2011 Idaho regulatory fee was estimated by using the 2010 actual payment. IPC's intrstate
gross revenue and the governor's budget recommendation was with 1 % of prior year therefore,
it was determined the 2010 Base was an appropriate estimate for 2011. The Oregon regulatory
fee consists of two fees, Oregon PUC fee and Oregon Deparent of Energy fee. For the test
year 2011, the Oregon PUC fee was the actual 2011 fee and for the Oregon Deparent of
Energy fee, the 2011 estimate was based upon prior year's tax rate multiplied ties the current
year revenue.
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Licenses
The 2011 Wyoming license was estimated using the prior year's tax rate applied to the estimated
2011 Wyoming assessed value. The 2011 Shoshone-Banock license fee was estimated using
the prior year's actual.
Franchises
The Oregon frnchise tax was determined by applyig a city frachise rate to its corresponding
electrc revenue. For 2011, each cities applicable ta rate was applied to estimated city revenue.
Forecast Adjustment I-Idaho Energy Resources Co.
("IERCQ") Cost of Service Components
FERC Accounts 418.1 and 419
Description
Account 418.1 includes the utility's equity in the earngs or losses of subsidiar companies for
the year. Account 419 includes interest revenues on securties, loans, notes, advances, special
deposits, tax refuds, all other interest-bearng assets, and dividends on stocks of other
companes, whether the securties on which the interest and dividends are received are cared as
investments or included in sinng or other special fud accounts.
Forecast Methodology
Forecast Adjustment I decreases Idaho Energy Resources Co. ("IERCO") Cost of Service
Components (Accounts 418.1 and 419) by $945,499 below the 2010 Base of $7,575,497
resulting in a projected 2011 net income of $6,629,998.
IPC owns 100% of Idao Energy Resource Company ("IERCO"), which has a one-thd joint
ventue interest in Bridger Coal Company ("BCC"), a mine that supplies coal to the Jim Bridger
plant. PacifiCorp, Inc. owns the remaing two-thds interest and is the mine's operating parer.
As a one-third owner in BCC, IERCO is entitled to one-thrd of the BCC net income and
cash flows.
The projected 2011 net income of $6,629,998 incorporates PacifiCorp's projected activity for the
BCC mine. IERCO's overrding royalties are determined by the location and lease under which
BCC is ming. The three leases are with the BLM, Union Pacific Railroad, and State of
Wyomig, and each lease pays at a different rate. The overrding royalty was grated to BCC
from IERCO, who in tu received them from IPC as advance royalties in the past. Coal royalty
payments have no impact on IERCO's net income as revenue is recognzed when paid by BCC,
and expense recognzed when remitted to IPC.
Income taxes are calculated at the federal ta rate of 35% as Wyoming has no state income tax.
Taxes are accrued and paid durg the calendar year.
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As discussed in the Rate Base Components section that follows, IERCO maintains an
intercompany note with IPC that accrues interest monthly at IPC's short-term borrowing rate,
which is projected to be .75% in 201 1. For puroses of the Cost of Service Component of
IERCO, the intercompany interest expense net of income tax is added back to increase IERCO's
net income.
Forecast Adjustment J-Allowance for Funds Used During
Construction ("AFUDC") Related to Hells Canyon Relicensing
FERC Accounts 107
Description
Account 107 (Constrtion Work in Progress) includes the total of the balances of work orders for
electrc plant in process of constrction. Work orders shall be cleared from ths account as soon
as practicable after completion of the job. Expenditues on research, development, and
demonstration projects for constrction of utility facilities are to be included in a separate
subdivision in this account. Also included in ths account is an Allowance for Funds Used
During Constuction ("AFUDC"). AFUDC includes the net cost for the period of construction
of borrowed fuds used for constrction puroses and a reasonable rate on other fuds when
so used, not to exceed, without prior approval of the Commission. The rates shall be
determined annually.
Forecast Methodology
Forecast Adjustment J is $0, resulting in the AFUDC related to Hells Canyon Relicensing
(Account 107) remaing the same as the 2010 Base.
IPC began incurng Hells Canyon relicensing costs in 1999. These relicensing efforts are
financed from internally generated fuds and from outside sources including short-term debt,
long-term debt and new equity. IPC accrues and capitalizes these fiaicing costs to account 107
as AFUDC durg the constrction phase of the project. AFUDC is calculated monthy using a
rate determned by a FERC formula. In the 2008, Idaho General Rate Case Order (IPUC Order
No. 30722), IPC requested and was granted the inclusion of the AFUDC related to Hells Canyon
Relicensing in the revenue requirement.
As of December 31,2009 and 2010, Hells Canyon Relicensing, account 107, balances equaled
$121,531,533 and $130,209,857, respectively. Of these balances, accumulated AFUDC was
$42,165,895 in 2009 and $50,629,008 in 2010.
Whle AFUDC continues to increase relating to the Hells Canyon Relicensing efforts, IPC is
requesting recovery ofthe same amount ($6,815,472) previously included the 2008 General Rate
Case and subsequently approved in IPUC Order No. 30722.
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RATE BASE COMPONENTS
Forecast Adjustment K-Electric Plant in Service
Table 1-FERC Account 101
Description
This account includes the original cost of electrc plant that is included in accounts 30 i to 399
(referred to herein as plant accounts). It is described as being owned and used by the utility in its
electrc utility operations and having an expectation of life in service of more than one year from
date of installation, including such property owned by the utility but held by nominees. The cost
of additions to and improvements of propert leased from others, which are includable in ths
account, are recorded in subdivisions separte and distinct from those relating to owned propert.
Forecast Methodology
Forecast Adjustment K increases Electrc Plant In Service (Account 101) by $165,872,190 above
the 2010 Base. Electrc Plant In Service has been presented using a theen-month average.
The methodologies used for plant additions and retiements are described below.
Plant Additions to Electric Plant In Service
Projected 2011 plant additions to Electric Plant In Service were developed based on the size of
Constrction Work in Process ("CWIP") projects as of year-end 2010 plus the expected 2011
capital expenditues. These capital projects were segregated into pools of greater than and less
than $2 milion. Capital projects greater than $2 milion were considered to be known and
measureable. For capital projects less than $2 milion, an historical methodology was developed.
Once CWIP project tyes for both pools were determined, the results were then combined and
allocated to FERC plant accounts 301 though 399 using a five year historical average.
This methodology is consistent with that used in Idao's 2008 General Rate Case (Case
No. IPC-E-08-1O).
Projected 2011 Plant Additions
Capital Projects in Excess of $2 Millon. Large capital projects with total costs in excess of
$2 milion were determined to be known and measurble adjustments for the 2011 unadjusted
test year. Actual capital expenditues in CWIP as of year-end 2010, plus expected 2011 capital
expenditues were used in determnig the amount that would close to plant by year-end 2011.
Allowance for Funds Used Durg Constrction ("AFUDC") was accrued on the CWIP balances
prior to their projected close. In addition, these projects' capital account balances, projected
expenditues, and the timing of closes to plant were reviewed by business unt managers familiar
with the projects.
The total amounts for the plant additions in the pool of over $2 milion in capital expenditues
were assigned CWIP project tyes based on the natue of each individual project.
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Capital Projects Less Than $2 Millon. In recogntion of the curent uncertin market
conditions, anticipated 2011 plant closings were set equal to actual 2010 plant closings for
similar-sized projects.
The total amounts for the plant additions in the pool of under $2 milion in capital expenditues
were then allocated to the CWIP project types based on a thee-year historical average.
All vehicle purchases were considered in total as a single project for ths purpose.
Allocation to FERC Plant Account
The above CWIP project tye pools were combined for fmal allocation to FERC plant accounts.
For this allocation, actual fmal closings from CWIP account 107 into Electrc Plant In Service,
account 101 were analyzed for the five-year period 2005 though 2009. Final closing amounts in
the PeopleSoft Asset Management system were used to allocate closings to plant accounts rather
than pre-close amounts. Final closes represent the "as built" property unts after the constrction
and work order has been completed and reconciled, whereas pre-closes are based on work order
estimates and may not be reflective of the fmal close distrbution. For each CWIP project tye,
the percentage allocation to FERC plant accounts 301 though 399 was determed by the ratio
of the five-year historical plant account closing for that CWIP project tye.
Retirements from Electric Plant In Service
Retirements were analyzed for the five-year period 2005 though 2009. Retirements by FERC
plant account were determined and compared to the closings by FERC plant account for the
same period. Retirements by FERC plant account were estimated by calculating the historical
percentage of retirements to additions for the five-year period.
The following FERC plant accounts have known retirement dates based on vintage layers and
were not estimated:
. Account 302-Softare
· Account 303-Franchises and Consents
. Account 391~Furitue
. Account 393-Stores Equipment
. Account 394-Shop Tools
. Account 395-Laboratory Equipment
· Account 397-Communcation Equipment
. Account 398-Miscellaneous Equipment
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Forecast Adjustments L & M-Accumulated Provision for
Depreciation and Amortization
Table 2-FERC Accounts 108 and 111
Description
Account 108 is credited for amounts charged to account 403, Depreciation Expense, or to
cleag accounts for curent depreciation expense for electrc plant in serice. At the time of
retirement of depreciable electrc utility plant, ths account is chaged with the book cost of the
propert retired and cost of removal and then credited with the salvage value and any other
amounts recovered such as insurance. When retired, costs of removal and salvage are originally
entered in retirement work orders, the net total of such work orders may be included in a separate
subaccount hereunder. Upon completion of the work order, the proper distrbution to
subdivisions of ths account shall be made for general ledger and balance sheet puroses as a
single composite provision for depreciation. For purposes of analysis, however, each utility shall
maintain subsidiar records in which this account is segregated according to the fuctional
classification of electrc plant in service. Account 111 is credited with amounts charged to
account 404, Amortization of Limted-Term Electrc Plant, for the curent amortization of
limited-term electrc plant investments.
Forecast Methodology
Forecast Adjustments L & M increase Accumulated Provision for Depreciation and
Amortization (Accounts 108 and 111) by $63,737,756 and $2,820,040 respectively, above the
2010 Base. The accumulated provision for depreciation and amortization has been presented
using a theen-month average. The 2011 forecast was developed by first determing the 2010
monthly balances and then building upon that to determine the 2011 theen-month account
balances. The process began with the year-end 2010 accumulated depreciation and amortization
account balances which were rolled forward monthly using the estimated 2011 depreciation and
amortization expense accruals, retirements, salvage, and removal costs. See account 403 and 404
in the Cost of Service Components section for discussion with respect to the depreciation and
amortization accrual calculation and Electrc Plant In Service, account 101 in the Rate Base
Components section for discussion of the method of determinig retirements. The five-year
(2006-2010) average salvage, removal costs, and retirements were then calculated. The salvage
and removal averages as a percentage of the retirement average were used to estimate monthly
salvage and removal costs. Those amounts were allocated to the transmission and distrbution
FERC plant accounts in their respective ratio to estimated retirements.
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Forecast Methodology Manual Idaho Power Company
Forecast Adjustment N-Materials and Supplies
Table 3-FERC Accounts 154 and 163
Description
Account 154 includes the cost of materials purchased primarly for use in the utility business for
constrction, operation, and maintenance purposes. Materials and supplies issued are credited
hereto and charged to the appropriate constrction, operating expense, or other account on the
basis of a unt price determined by the method of inventory accounting. Account 163 includes
the cost of supervision, labor, and expenses incured in the operation of general storerooms,
including purchasing, storage, handling, and distrbution of materials and supplies. This account
is cleared by adding to the cost of materials and supplies issued a suitable loading charge which
distrbutes the expense equitably over stores issues. The balance in the account at the close of the
year shall not exceed the amount of stores expenses reasonably attbutable to the inventory of
materials and supplies.
Forecast Methodology
Forecast Adjustment N reflects a $657,159 decrease in Materials and Supplies (accounts 154
and 163) below the 2010 Base.
The thieen-month average decrease was due partially to a concerted effort to reduce
inventories, as a result of the economic slow-down. Specifically, account 154.220 from the
December 2009 to December 2010 decreased by $1,481,473. Additionally, IPC over cleared
overheads included in the 163 accounts by $935,723. However, while the thireen-month average
reflects a decrease to rate base, the December 2011 year-end balance is expected to increase over
the 2010 year-end balance by $1,590,713 based on the following:
. M & S Steam Plant is forecasted to increase $241,336 based on the Januar 2009 through
February 2011 actuals.
. The new Langley Gulch gas plant is expected to cause an increase in inventories
by $250,000.
. Stores Expense Undistrbuted was increased $1,071,985 to the amount forecasted by the
Financial Stores Loading model at December 31, 2011. As stated above, the 2010 endig
balance in these accounts was arificially low due to inventory issues being greater than
projected in the fourth quaer 2010.
. Stores Expense Steam Plant is estimated to decrease $495,149 based on trending actual
month-end balances for the time period Janua 2009 through Februar 2011.
. The balance in the Sales Tax account (163500) is forecasted to increase $522,541 due to
the 2010 ending balance in ths account being lower than required due to timing varances
with issues and invoice processing.
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Forecast Adjustment a-Other Deferred Programs
Table 3-FERC Accounts 182.3 and 186
Description
This account includes the amounts of regulatory assets not includable in other accounts resulting
from the ratemakng actions of regulatory agencies.
Forecast Methodology
Forecast Adjustment 0 increases Other Deferred Programs (Accounts 182.3 and 186) by
$146,580 above the 2010 Base.
Accounts 186.722 and 186.770-American Falls Bond Refinancing, IPUC Order No. 25880.
These deferred costs are financing costs related to American Falls Bond issuances. The total
montWy amortization of these two bonds is $5,212 per month or $62,552 per year. IPC has
reduced the 2010 Base for one year of additional depreciation for $62,552, resulting in a total
deferr of$823,593.
Account 182.349-Intervenor Funding, IPUC Order No. 30722. This account includes
intervenor fuding ordered in the 2008 General Rate Case (Case No. IPC-E-08-1O). In that case,
IPC was ordered to pay the Communty Action Partership Association of Idaho ("CAP AI")
$9,183 in costs as a result of their paricipation in the case. IPC has assumed a one-year
amortization period for recovery of these costs in ths case. This reduced the deferral by the 2010
Base of $10,572 including accrued interest, resulting in a total deferral forecast of$O.
Account 182350-Intervenor Funding, IPUC Order No. 30722. This account includes
intervenor fuding ordered in the 2008 General Rate Case (Case No. IPC-E-08-1O). In that case,
IPC was ordered to pay the Idaho Irrgation Pumpers Association, Inc. ("Irgators") $30,817 in
fees and expenses as a result of their partcipatiori in the case. IPC has assumed a one-year
amortization period for recovery of these costs in ths case. This reduced the deferrl by the 2010
Base of$35,480 including accrued interest, resulting in a total deferr forecast of$O.
Account 182.345-itizens Utity Board ("CUB") 2010 Funding Grant, OPUC Order
No. 10-406. IPC was ordered in Docket UM 1504(1) to fud $30,000 to CUB pursuant to the
terms of the Intervenor Funding Agreement by and among IPC and CUB and approved by the
OPUC in Order no. 10-396. As a result, IPC has assumed a one-year amortization period for
recovery of these costs in ths case. This reduced the deferrl by the 2010 Base of $30, 1 00
including accrued interest, resultig in a total deferrl balance of $0.
Account 182.339-SFAS 87 Capitalized Pension Costs, OPUC Order No. 10-064. IPC
included a forecast adjustment of$383,271 for its capitalized portion of its SFAS 87 Capitalized
Pension Costs. This brigs the total 2011 estimate to $1,323,161.
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Account 182.369-Grid West Loans, OPUC Order No. 06-483. IPC has included a reduction
to its 2010 Base of $14,191 for one year of additional amortization, briging the test year
deferrl balance to $44,937.
Account 182.304-rid West Loans, FERC Portion. IPC has included a reduction to its 2010
Base for $83,796 for one year of additional amortization, briging the test year deferrl balance
to $111,728.
Forecast Adjustment P-Plant Held for Future Use
Table 3-FERC Account 105
Description
This account includes the original cost of electrc plant owned and held for futue use in electrc
service under a definite plan for such use and includes property acquired but never used by the
utility in electrc service, but held for such service in the futue under a defite plan
and propert previously used by the utility in service, but retired from such service and held
pending its reuse in the futue, under a definite plan, in electrc service.
Forecast Methodology
Forecast Adjustment P increases Plant Held for Futue Use (Account 105) by $210,000 above
the 2010 Base
IPC developed its 2010 Base by removing from the 2010 actul Plant Held for Futue Use those
properties that it either plans to sell, wil be possibly split and partially sold, strctues or
improvements that wil be removed prior to constrction and properties for which the use is
uncertin.
In addition, IPC included in its forecast adjustment $210,000 for the acquisition of four
additional parcels of land that wil be acquired by year-end 2011. These include land purchases
for the Buhl, Justice and Montour substations and Peterson substation expansion.
Forecast Adjustment Q-Customer Advances for
Construction ("CAC")
Table 3-FERC Account 252
Description
Account 252 includes advances by customers for constrction which are to be partially or wholly
refuded. When a customer is refunded the entire amount to which he or she is entitled according
to the agreement or rule under which the advance was made, any remaing balance is credited to
the appropriate plant account.
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Forecast Methodology
Forecast Adjustment Q decreases the Customer Advances for Construction (Account 252) 2010
Base by $6,304,446, based on an estimated thrteen-month average balance.
IPC investigated varous methods to forecast ths account, including the average dollar balance
per customer methodology that was used in the 2008 Idaho General Rate Case (IPC-E-08-1O).
However, because of new Rule H changes ths method became inaccurate. Therefore, IPC
determined that because customer advances are drven priarily by customer growt, the most
reasonable method was to star with the December 2010 Base for account 252, removing all
balances related to Constrction Work in Progress, then reducing the balance by the subdivision
lots completed in 2006, as these wil be either refuded or absorbed by the end of 20 11. IPC then
reduced the balance furter by anualizing the 2010 lot refunds for work completed from 2007 to
2009 as the estimate for 2011 lot refuds that fall inside the 5-year period for refuds. This
method reflects the IPC's anticipation that market conditions in 2011 wil be similar to those
existig in 2010. Finally, IPC added in the estiated ending unusua conditions and network
transmission upgrde balances. IPC's removal of balances associated with Constrction Work in
Progress is because these should not be included to reduce rate base since Constrction Work in
Progress is not a rate-based item. Please see the analysis in the table below:
2011 Forecast of Customer Advances Total
$19,146,93712/31/10 LXMN lot refund balance excluding net work transmission upgrades and unusual
conditions
2006 lot refund balance to be refunded or absorbed in 2011
2011 estimated refunds estimated ending balances
Unusual conditions refunds estimated ending balance
Network transmission upgrades estimated balance excluding work in progress
(4,497,506)
(831,772)
973,225
837,500
12/31/11 estimated customer advances excluding work in progress and unusual conditions $15,628,3841
1 This amount represents the estimated year-end balance. IPC has estimated the thirteen-month balance of $17,261,533 based on
the shape of the 2010 actual thirteen-month average balance.
Forecast Adjustment R-Idaho Energy Resources Co.
("IERCO") Rate Base
Table 3-FERC Accounts 123.1, 186, and 145
Description
Account 123.1 includes the CQst of investments in securties issued or assumed by subsidiar
companes and investment advances to such companes, including interest accrued thereon when
such interest is not subject to curent settlement plus the equity in undistrbuted eargs or
losses of such subsidiar companes since acquisition. This account is credited with any
dividends declared by such subsidiaries. This account is maintained in such a maner as to show
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Forecast Methodology Manual Idaho Power Company
separately for each subsidiary: (I) the cost of such investments in the securties of the subsidiar
at the time of acquisition, (2) the amount of equity in the subsidiar's undistributed net eargs
or net losses since acquisition, and (3) advances or loans to such subsidiar. Account 145
represents notes receivable from associated companes. Account 186 includes all debits not
elsewhere provided for, such as miscellaneous work in progress, and unusual or extraordinary
expenses, not included in other accounts, which are in process or amortization and items the
proper fial disposition of which is uncertin.
Forecast Methodology
Forecast Adjustment R increases Idaho Energy Resources Co. ("IERCO") Rate Base
(Account 123.1,186 and 145) by $154,130 above the 2010 Base.
IPC's projected 2011 investment in IERCO is based on actual activity for 2010 at the Bridger
Coal Company ("BCC") mine that supplies coal to the Jim Bridger thermal plant. As a one-thrd
owner in BCC, IERCO is entitled to 33% of the BCC net income and cash flows.
. Account 123.1-Investment in IERCO. The 2011 thrteen-month average investment in
IERCO balance is projected to increase $7,609,643 from the 2010 Base thrteen-month
average balance of$67,582,237 to $75,191,880. IERCO's investment in BCC is
accounted for using the equity method. BCC income, IERCO income, and IERCO capital
contrbutions to BCC increase the investment balance; while Bec dividend distrbutions
to IERCO reduce the investment balance. The $7,609,643 increase is due to reinvesting
one year wort of after ta earngs into BCC. No dividend assumptions were made
durng the forecast test year. Instead, any extra cash remaining after payig operating
expenses and capital investment are returned to IPC via the intercompany note (see below
for discussion of account 145-IERCO Intercompany Note).
. Account 18~Prepaid Coal Royalties. The 2011 thrteen-month average balance is
projected to decrease $68,132 from the2010 Base thirteen-month average balance of
$1,464,357 to $1,396,225. BCC overrding coal royalties are determned by the location
and lease under which BCC is minig. The overrding royalty was granted to BCC from
IERCO, who in tu received them from IPC as advance royalties in the past. Although
coal royalty payments have no impact on IERCO's net income, because revenue is
recognzed when paid by BCC and expense recognized when remitted back to IPC,
the payment flow serves to reduce the account 186 balance.
. Account 145-Notes Payable To/Receivable from Subsidiary. The 2011
thrteen-month average balance is projected to decrease $7,387,381 from the 2010
Base thrteen-month average balance of$19,880,651 to $12,493,269. The IERCO
intercompany note is the fuding mechansm whereby IERCO not only receives
distrbutions from and makes capital contrbutions to BBC, but also pays income taes
and dividends to !PC. The intercompany note activity is based on the projected 2011
BCC operating and capital budgets. Because capital expenditues have been leveling off,
BBC is projected to have extra cash in 2011 to reduce the note balance. Interest on the
intercompany note is based on IPC's short-term borrowing rates and accrues monthy.
The average interest rate used is .75%.
Page 30 Proprie~fi¥bit No. 20
Case No. IPC-E-11-08
T. Tatum, IPC
Page 35 of 35
RECEIVED
. BEFORE THE ZOll JUN -I PH 2= 44
!DAHO PI.:i~'L (~
IDAHO PUBLIC UTILITIES COMMISSION(ìE;~~ COi\\!'¡!: SSION
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
TATUM, 01
TESTIMONY
EXHIBIT NO. 21
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