20110602Noe Di, Exhibits.pdf

RECEIVED
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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
KELLEY NOE
1 Q.Please state your name and business address.
2 A.My name is Kelley Noe. My business address is
3 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 Regulatory Analyst I I.
7 Q.Please describe your educational background.
8 A.In May of 2004, I received a Bachelor of
9 Business Administration in Finance from Boise State
10 University.
11 Q.Please describe your business experience with
12 Idaho Power Company.
13 A.In September 2006, I accepted a position at
14 Idaho Power as a Financial Analyst in the Finance
15 Department. My primary duties included performing credit
16 reviews on current and prospective transmission customers
17 as well as providing the financial support for Grid
18 Operations, Planning, and Operations Analysis and
19 Development groups. In October 2010, I accepted a
20 Regulatory Analyst II position within the Regulatory
21 Affairs department of the Company. My duties as a
22 Regulatory Analyst II include gathering, analyzing, and
23 coordinating data from various departments throughout the
24 Company required for development of jurisdictional
25
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Idaho Power Company
1 separation studies, as well as other analyses that may be
2 required.
3 Q.What is the scope of your testimony in this
4 proceeding?
5 A.I am sponsoring testimony to summarize the
6 annualizing adjustments to the 2011 unadjusted forecast
7 test year data used by the Company for purposes of
8 forecasting the Company's rate base, revenues, and expenses
9 for the 2011 Test Year. My testimony will also quantify
10 the Idaho Jurisdictional Revenue Requirement resulting from
11 the Jurisdictional Separation Study ("JSS") for the 12
12 months ending December 31, 2011.
13 Q.Have you prepared exhibits for this
14 proceeding?
15 A.Yes. I am offering the following exhibits:
16 1.Exhibi t No. 22, Maj or Plant Additions
17 Annualized for 2011;
18 2.Exhibi t No. 23, Depreciation &
19 Amortization Annualizing Adjustments;
20 3.Exhibit No. 24, Summary of Payroll-
21 Related Annualizing Adjustments;
22 4.Exhibit No. 25, Development of System
23 Revenue Requirement; and
24 5.Exhibi t No. 26, Jurisdictional
25 Separation Study - Idaho Revenue Requirement.
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Idaho Power Company
1 Q.Could you briefly summarize how the Company
2 developed its 2011 Test Year?
3 A.Yes. As described in the testimonies and
4 exhibits of Mr. Douglas N. Jones and Mr. Timothy E. Tatum,
5 the development of the 2011 Test Year begins with 2010
6 actual financial data ("2010 Actuals"). The 2010 Actuals
7 were adjusted to reflect currently approved ratemaking
8 adjustments and arrive at 2010 adjusted actual financial
9 information ("2010 Base"). The 2010 Base was then adjusted
10 to reach 2011 forecasted financial levels ("2011 Unadjusted
11 Test Year"). After the 2011 Unadjusted Test Year figures
12 were compiled, they were provided to me as the starting
13 point for the development of the Company's total 2011 Test
14 Year figures used in this filing.
15 Q.Were any additional adj ustments made to the
16 2011 Unadjusted Test Year amounts to reach the Company's
17 total 2011 Test Year figures?
18 A.Yes. Exhibit Nos. 22 through 26 illustrate
19 the annualizing adjustments used to develop the total 2011
20 rate base and net income figures used in the Company's 2011
21 Test Year.
22 Q.Please describe the role of annualizing
23 adjustments in this filing.
24 A.At Mr. Tatum's direction, I performed a number
25 of annualizing adjustments to amounts that are incurred
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Idaho Power Company
1 wi thin the test year, but need to be reflected for the full
2 year on an ongoing basis.
3 Q.Please describe the annualizing adjustments
4 made for "Maj or Plant Additions."
5 A.Major Plant Additions illustrated in Exhibit
6 No. 22 are defined as those investments exceeding $2
7 million that will close to the Company's electric plant in
8 service accounts during the calendar year 2011. A month-
9 by-month forecast of 2011 electric plant in service and the
10 13-month average balances provided by Mr. Jones form the
11 beginning point for the analysis. Annualizing adj ustments
12 are applied only to the 2011 plant additions that qualify
13 as Maj or Plant Additions to establish the amount of
14 investment that would have been recorded had the plant been
15 in service throughout the entire year. The difference
16 between what had been forecast for these investments in the
17 initial analysis compared to the annualized forecast, as
18 illustrated in column 3 - Net Annualizing Adjustments, is
19 the $31,599,458 annualizing adjustment for the Company's
20 electric plant in service investment in this filing.
21 Additional annualizing adjustments associated with Major
22 Plant Additions include $132,419 in property taxes (column
23 6 - Annual Composite Property Tax) and $12,008 in property
24 insurance (column 8 - Annual Insurance Expense). Because
25 none of the Major Plant Additions was attributable to load
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Idaho Power Company
1 growth (see Summary on page 2 of Exhibit No. 22), an
2 imputed revenue adj ustment was not required.
3 Q.Please describe Exhibit No. 23 - Depreciation
4 & Amortization Annualizing Adjustments.
5 A.Depreciation and amortization expenses are
6 forecast on a month-by month basis during 2011 and
7 summarized in the column entitled "Forecasted Depreciation
8 Expense." The expenses for December 2011 are multiplied by
9 12 to calculate the "Annualized Depreciation Expense." The
10 difference between these two columns equals the
11 "Annualizing Adjustment" of $2,225,161 depreciation expense
12 and $ 18 9,455 amortization expense. Adj ustments of
13 $1,125,683 to Accumulated Depreciation and $94,728 to
14 Accumulated Amortization, illustrated as the "Reserve
15 Adjustment," are conventionally computed as half the
16 expense amounts.
1 7 Q .Please continue by explaining Exhibit No. 24,
18 Summary of Payroll-Related Annualizing Adjustments.
19 A.There are two additional labor-related
20 annualizing adj ustments in this filing totaling $4,332,883.
21 The first adjustment utilizes 2010 actual labor data
22 as a proxy to annualize 2011 payroll and reflect an entire
23 year of expense at that year-end level. Because the method
24 applied to forecast the 2011 operations and maintenance
25 ("O&M") labor expense (detailed in the testimony by Mr.
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Idaho Power Company
1 Tatum) provided only a forecast of the annual 2011 O&M
2 labor expense, a December labor expense amount from which a
3 conventional annualizing labor adjustment could be
4 calculated was not known. Therefore, an annualizing
5 adjustment based upon actual 2010 labor was calculated and
6 used as a proxy to adj ust the O&M labor total for the 2011
7 Test Year. After applying the Company's Operations &
8 Maintenance and benefit loading percentages, the
9 annualizing adjustment is $1,955,023.
10 The second adjustment of $2,377,859 reflects the
11 projected 2012 salary structure adjustment of 2 percent.
12 This adjustment was applied to the annualized 2011 payroll
13 and has been adj usted by the Company's O&M and benefit
14 loading percentages.
15 Q.Please describe Exhibit No. 25, Development of
16 System Revenue Requirement.
17 A.Exhibit No. 25 provides the development of the
18 adj usted total electric system rate base and net income for
19 the test year ending December 31, 2011.
20 The first set of data, displayed in column 3 - "2010
21 Actual", is the unadjusted 2010 actual results of
22 operations provided by Mr. Jones. The adjustments proposed
23 by the Company for purposes of developing the 2011 adjusted
24 total electric system combined rate base and net income are
25 shown in columns 4, 6, and 8 with the total system adjusted
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Idaho Power Company
1 test year rate base, expenses, and revenues summarized in
2 column 9. The columns are as follows:
3 (1 )Column 4, titled "2010 Actual
4 Adj ustments" were provided by Mr. Jones and Mr. Scott
5 Wright. It reflects currently approved regulatory
6 adjustments that should be applied to the 2010 actual
7 results prior to applying methods to adjust to 2011 levels;
8 (2 )Column 5, titled "2010 Base" is the
9 adjusted base to which the methods to create a 2011 Test
10 Year were applied;
11 ( 3)Column 6, titled "Forecast Adjustments"
12 reflect the results of the various methods from the
13 Forecast Methodology Manual sponsored by Mr. Tatum and
14 detailed in his testimony, that were used to adj ust totals
15 from the 2010 Base to a 2011 Unadjusted Test Year.
16 (4) Column 7, titled "2011 Unadjusted Test
17 Year" includes the resulting dataset once the standard
18 regulatory adjustments and various methods were applied;
19 (5 )Column 8, titled "Annualizing
20 Adjustment" includes standard annualizing adjustments, to
21 reflect changes that occur within the test year, but need
22 to be incorporated for the full year on an ongoing basis.
23 All annualizing adjustments included in this filing were
24 discussed earlier in my testimony.
25
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Idaho Power Company
1 (6 )Column 9, titled "2011 Test Year" is
2 the resulting dataset for the 2011 Test Year (12 months
3 ending December 31, 2011).
4 Q.Please describe page 2 of Exhibit No. 25.
5 A.Page 2 of Exhibit No. 25 summarizes the
6 development of rate base components for the 2011 Test Year.
7 The total combined rate base, based on actual, unadjusted
8 2010 results was $2,392,731,926 (column 3, line 63). After
9 adjustments, the total combined rate base for the 2011 Test
10 Year increases to $2,478,471,160 (column 9, line 63).
11 Page 2 of Exhibit No. 25 also includes the
12 development of the total system net income for the 12
13 months ending December 31, 2011. Operating revenues are
14 summarized on line 69. Total operating expenses are
15 summarized on line 80.
16 Q.Have you prepared an exhibit that sets forth
17 the Idaho jurisdictional revenue deficiency?
18 A.Yes. I prepared Exhibit No. 26, titled
19 "Jurisdictional Separation Study - Idaho Revenue
20 Requirement" consisting of 35 pages.
21 Q.Please describe Exhibit No. 26.
22 A.Exhibi t No. 26 is the complete Jurisdictional
23 Separation Study report detailing the allocation of each
24 component of rate base, operating revenues, and expenses by
25 Federal Energy Regulatory Commission ("FERC") account
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Idaho Power Company
1 resul ting in the Idaho jurisdictional revenue deficiency.
2 The JSS is organized as follows:
3 . Summary of Results;
4 . Table 1 - Electric Plant in Service;
5
6
7
8
9
10
11
. Table 2 - Accumulated Provision for
Depreciation (and Amortization) ;
. Table 3 - Additions & Deductions to Rate
Base;
. Table 4 - Operating Revenues;
12 . Table 5 - Operation & Maintenance Expenses;
13
14
15
16
. Table 6 - Depreciation & Amortization
Expense;
17
.Table 7 -Taxes Other Than Income Taxes;
.Table 8 -Regulatory Debits &Credits;
.Table 9 -Income Taxes;
.Table 10 -Calculation of Federal Income
Tax;
18
19
20
21
22 . Table 11 - Oregon State Income Tax;
23
24
25
26
27
28
29
. Table 12 - Idaho State Income Tax and Other
State Income Tax;
. Table 13 - Development of Labor Related
Allocator;
. Table 14 - Allocation Factors; and
30 . Table 15 - Allocation Factors-Ratios.
NOE, DI 9
Idaho Power Company
1 Q.Please discuss the methodology used to
2 jurisdictionally separate costs in the preparation of this
3 study.
4 A.A three-step process was used to separate
5 costs among jurisdictions. The three steps are
6 classification, functionalization, and allocation of costs.
7 In all three steps, recognition was given to the way in
8 which costs are incurred by relating these costs to utility
9 operations.
10 Q.Would you please briefly explain the meaning
11 of classification, functionalization, and allocation?
12 A. Classification groups costs into three
13 categories: demand-related, energy-related, and customer-
14 related.
15 In addition to classification, costs are
16 functionalized; that is, costs are identified with utility
17 operating functions such as generation, transmission, and
18 distribution . Individual plant items are examined and,
19 where possible, the associated investment costs are
20 assigned to one or more operating functions . Once the
21 Company's total system costs are classified and assigned to
22 the appropriate function, they are allocated among
23 jurisdictions.
24 The process of allocation is one of apportioning the
25 total system cost among jurisdictions by introducing
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Idaho Power Company
1 allocation factors into the process. An allocation factor
2 is an array of numbers which specifies the jurisdictional
3 value as a share or percent of the total system quantity.
4 For example, in the case of energy-related costs, the
5 allocation factor is annual jurisdictional energy use,
6 adj usted for losses , divided by the total system energy
7 use.
8 Once individual accounts have been allocated to the
9 various jurisdictions, it is possible to summarize these
10 into total utility rate base and net income by
11 jurisdiction. The results are stated in a summary form to
12 measure adequacy of revenues for the jurisdiction under
13 consideration. The measure of adequacy is typically the
14 rate of return earned on rate base, which is compared to
15 the requested rate of return.
16 Q.Is the methodology used to separate costs by
17 jurisdiction and calculate the Idaho jurisdictional revenue
18 requirement in the present case primarily the same
19 methodology utilized in the Company's last general rate
20 case, Case No. IPC-E-08-10?
21 A.While the allocation methodology is primarily
22 the same as in the Company's last general rate case, there
23 are some proposed modifications in this filing. The
24 primary change in methodology addresses how the Company
25 proposes to allocate FERC Firm Transfer customers'
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Idaho Power Company
1 transmission and distribution investments and related
2 revenues and expenses.
3 Q.Why have you included this change in
4 methodology in regards to the FERC Firm Transfer customers?
5 A.This change in methodology was the direct
6 result of research by the Company's FERC & Regional
7 Regulatory Affairs group in conj unction with Mr. Tatum as
8 well as other members of the Regulatory Affairs group. The
9 proposed methodology was reviewed and approved by the
10 Company's Senior Management for use in the 2011 Test Year.
11 Q.Please describe the proposed change in
12 methodology to the allocation of the Company's FERC Firm
13 Transfer jurisdiction.
14 A.Under the Company's traditional jurisdictional
15 allocation methodology, allocations assumed that each
16 jurisdiction's transmission and distribution responsibility
17 was proportional to the demand that each jurisdiction
18 placed on the Company's system. The identical allocation
19 methodology was applied uniformly by the Company for both
20 its retail and Firm Transfer customers.
21 In 2006, the Company was authorized by the FERC to
22 implement a formula rate for transmission service provided
23 under its Open Access Transmission Tariff ("OATT"). It
24 should be noted that Idaho Power Company itself is the
25 Company's largest transmission customer because its retail
NOE, DI 12
Idaho Power Company
1 customers are subj ect to the OATT formula rates as
2 authorized by FERC when the Company buys and sells on
3 behalf of its retail customers.
4 The FERC's OATT formula rate calculation does not
5 synchronize with the Company's currently approved
6 allocation methodology in significant ways. Under the
7 formula rate, FERC prescribes defined classifications of
8 plant and expenses authorized for functionalization as
9 transmission and thereby billable to its Firm Transfer
10 customers under the rates of the Company's OATT. This
11 FERC-spetific functionalization of transmission plant and
12 expenses has become divergent from the Company's current
13 JSS model in the following areas:
14 .The OATT rate does not allow for
15 inclusion of any distribution facilities or expenses
16 and therefore, allocation of distribution-related
17 costs to the company's Firm Transfer customers
18 should be removed from the retail ratemaking model.
19 .The OATT rate specifically excludes
20 Load Dispatching Expenses so they should not be
21 allocated to Firm Transfer customers in the retail
22 ratemaking model.
23 .The OATT rate specifically excludes
24 generator step-up stations and generator
25 interconnection facilities so they should not be
NOE, DI 13
Idaho Power Company
1 allocated to Firm Transfer customers in the retail
2 ratemaking model.
3 The OATT rate formula' s divergence from the
4 Company's currently approved rate making methodology
5 manifests itself in a host of ways creating many
6 opportunities for double-counting or exclusions if
7 attempting to harmonize the two differing methodologies
8 into a single allocation method. Therefore, the Company is
9 proposing to change JSS methodology to allocate all Firm
10 Transfer investments, expenses and revenues to the retail
11 jurisdictions, in a manner similar to how the other two
12 public utili ties providing service in Idaho (Avista - AVU-
13 E-10-01 and Rocky Mountain Power - PAC-E-02-03) handle
14 FERC-related costs and revenues.
15 Q.Besides the FERC Firm Transfer-related
16 allocation changes, is the Company proposing any other
17 methodology modifications?
18 A.Yes. Since the last general rate case, the
19 Company has evaluated its allocation of tax-related rate
20 base and expense line items. In each instance, the Company
21 has sought to more properly align the tax item's allocation
22 wi th its causation or fundamental association. For
23 example, Account 190 - Accumulated Deferred Income Taxes
24 has formerly been allocated over the Company's "Total
25 Plant" investment. However, upon examination, revisions in
NOE, DI 14
Idaho Power Company
1 this filing are made to allocate portions of Account 190
2 over "DA252 - Customer Advances for Construction" and
3 "Labor" to more closely align allocations with the primary
4 components wi thin the account. Another example is "IERCO
5 Taxable Income" which is no longer being allocated by
6 "State Taxable Income" but rather allocated in this filing
7 over the Company's energy allocator in order to be
8 consistent with the allocation of IERCO rate base
9 investment and related income.
10 In summary, each tax-related line item in the JSS
11 for this filing has been evaluated to determine the most
12 appropriate allocation based on causation or fundamental
13 association to the Company's investments or other
14 underlying foundation. A comprehensive list of all the
15 tax-related changes is included in my workpapers.
16 Q.How have the various functional plant and cost
17 items been allocated?
18 A.The average of the 12 monthly coincident peak
19 demands was used to allocate the demand-related costs.
20 This allocation method has been used by the Company for at
21 least two decades in all of its filings requiring a
22 jurisdictional separation study. This allocation method
23 was adopted by this Commission and also accepted by the
24 Oregon Public Utility Commission. The demand-related
25 allocation factors used in the study are designated as D10,
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Idaho Power Company
1 D11, D12, and D60. The respective values used in these
2 demand allocation factors are shown at line numbers 1035
3 through 1038 of Exhibit No. 26.
4 Q.How were the energy-related expenses allocated
5 among jurisdictions?
6 A.Energy-related expenses were allocated based
7 on normalized jurisdictional kilowatt-hour sales and
8 adjusted for losses to establish energy requirements at the
9 generation level. The energy-related allocation factors
10 used in the study are designated as E10 and E99. The
11 respecti ve values used in these energy allocation factors
12 are shown on lines 1041 and 1042 of Exhibit No. 26.
13 Q.What was the method by which you allocated
14 customer-related costs?
15 A.The principal customer-related expenses which
16 required allocation were meter reading (FERC Account 902)
17 and customer accounting and billing (FERC Account 903).
18 These accounts were allocated based upon a review of actual
19 Company practice of reading meters and preparing monthly
20 bills or statements.
21 Q.What method was used to allocate certain
22 labor-related administrative and general expenses?
23 A.In accordance with FERC-approved procedures,
24 administrative and general expenses were allocated in
25 accordance with functionalized wages and salaries. These
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Idaho Power Company
1 labor-related allocation factors are shown on lines 835
2 through 1030 of Exhibit No. 26.
3 Q.Please describe the derivation of the 2011
4 total system allocation factors used in this case.
5 A.The allocation factors in the 2011 JSS were
6 based on either the 2010 year-end data or 2011 assumptions.
7 The capacity or demand-related allocation factors (D10,
8 D11, D12, and D60) were created using the 2010 demand
9 ratios from the load research sample applied to the 2011
10 Test Year energy. The energy-related allocation factors
11 were the 2011 Test Year load at generation level (E10) and
12 at customer level (E99).
13 Q.Briefly describe the manner in which you
14 allocated electric plant in service as shown in Table 1 of
15 Exhibit No. 26.
16 A.Production plant was allocated to all
17 jurisdictions based on the average of the 12 monthly
18 coincident peaks. Unless otherwise noted, allocation of
19 transmission and distribution plant was based on the same
20 methodology.
21 Q.Would you describe the functional categories
22 used for allocation and direct assignment of transmission
23 plant and distribution substations?
24 A."Transmission facilities" are the facilities
25 that form the bulk of the power transmission system
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Idaho Power Company
1 together with transmission, step-up substation facilities
2 required to introduce the Company's generation into the
3 power supply system, and include facilities rated at 500
4 kilovolts ("kV") through 100 kV. "Distribution facilities"
5 refer to lower voltage lines and the substation facilities
6 that provide localized service. Some transmission and
7 distribution facilities were directly assigned to the
8 customers who paid for the exclusive use of those
9 facili ties. As previously discussed in this testimony,
10 there are some proposed modifications to the direct
11 assignment and allocation of FERC Network Service-related
12 investments in this filing.
13 Q.Please describe the manner in which you
14 allocated general electric plant in service.
15 A.General plant was allocated on the same basis
16 as the sum of the allocated investments in production,
17 transmission, and distribution plant.
18 Q.How have you allocated the accumulated
19 provision for depreciation and amortization of other
20 utility plant?
21 A.Accumulated Provision for Depreciation was
22 allocated among jurisdictions as shown on Table 2 of
23 Exhibit No. 26. The accumulated totals for each type of
24 production plant and for each primary plant account in
25 other functional groups were allocated based on the related
NOE, DI 18
Idaho Power Company
1 plant account as allocated in Table 1. Amortization of
2 other utility plant was functionalized and then allocated
3 based on the related plant items as allocated in Table 1.
4 Q.Please describe Table 3 of Exhibit No. 26.
5 A.Table 3 details the allocation of all other
6 additions to or deductions from rate base. Deductions from
7 rate base include customer advances for construction that
8 were directly assigned to customers by jurisdiction, and
9 the accumulated deferred income taxes that were allocated
10 by plant, customer advances for construction, and labor.
11 Addi tions to rate base include:(1) materials and supplies
12 which were functionalized and allocated by the respective
13 plant allocators, (2) fuel inventory that was allocated on
14 the basis of energy, (3) components of IERCO, the Company's
15 fuel subsidiary, which were allocated based on energy, and
16 (4) Commission-ordered deferred investment was either
17 directly assigned to a specific jurisdiction or allocated
18 based on energy.
19 All rate base items, with the exception of
20 accumulated deferred income taxes and other deferred
21 programs, reflect a 13-month average of ending balances.
22 Q.Please describe Table 4 of Exhibit No. 26.
23 A.Table 4 contains the adjusted firm operating
24 revenues directly assigned to each jurisdiction for the
25 test year (12 months ending December 31, 2011).
NOE, DI 19
Idaho Power Company
1 Contractual Hoku first block energy sales revenues are
2 allocated to each jurisdiction in proportion to generation-
3 level energy usage (with an equal offset in PURPA purchased
4 power in Account 555.1). Opportunity sales, non-firm
5 energy sales to other utili ties, are also credited to each
6 jurisdiction in proportion to generation-level energy use.
7 Other operating revenues were either allocated among
8 jurisdictions in a manner that offset related allocations
9 of rate base or, where a particular revenue item could be
10 associated with a specific jurisdiction, directly assigned.
11 Q.Briefly describe the methods by which
12 Operation and Maintenance Expenses were allocated.
13 A.The allocation of each O&M expense is detailed
14 on Table 5 of Exhibit No. 26. In general, the basis for
15 each allocation is identifiable with the source code listed
16 on Exhibit No. 26. Demands are identified by a source code
17 beginning with a "D" prefix, energy use is identified by a
18 source code beginning with an "E" prefix, related plant is
19 identified by a line number source code, and customer-
20 weighted allocation factors begin with a "CW" prefix.
21 Q.In what manner are supervision and engineering
22 expenses treated throughout the allocation of operation and
23 maintenance expenses?
24 A.For the applicable expense account in each
25 functional group, the labor component was separately
NOE, DI 20
Idaho Power Company
1 allocated in accordance with the detail provided on Table
2 13 of Exhibit No. 26. The total of allocated labor in each
3 functional group became the basis for the allocation of
4 supervision and engineering expense. Total allocated labor
5 expense served the additional purpose of allocating
6 employee pension and other labor-related taxes and
7 expenses. Table 13 of Exhibit No. 26 details the
8 development of all the labor-related allocation factors
9 used in this study.
10 Q.Please describe Table 6 of Exhibit No. 26.
11 A.The allocation of depreciation expense and
12 amortization of limited term plant is set forth on Table 6.
13 These expenses were identified by type of production plant
14 or by primary plant account for other functional plant
15 groups and allocated consistent with the related plant
16 account.
17 Q.Please describe Table 7 of Exhibit No. 26 and
18 the allocation of Taxes Other Than Income Taxes.
19 A.Taxes Other Than Income Taxes were treated
20 individually and allocated in a manner consistent with the
21 bases by which the respective taxes are assessed.
22 Q.Please describe Table 8 of Exhibit No. 26.
23 A.Table 8 of Exhibit No. 26 details the
24 amortization of regulatory debits and credits.
25 Q.Please describe Table 9 of Exhibit No. 26.
NOE, DI 21
Idaho Power Company
1 A.The expenses. shown on Table 9 consist of
2 deferred income taxes and the investment tax credit
3 adjustments which were allocated based on the Company's
4 plant investment and net income before tax adjustments.
5 State and federal income tax liabilities are also
6 summarized on Table 9. The income taxes shown on Tables 10
7 through 12 were obtained from the Company's Tax Department.
8 Q.Please describe how you allocated federal and
9 state income taxes shown on Tables 10 through 12 of Exhibit
10 No. 26.
11 A.The respective tax bases were developed, and
12 taxes were calculated directly for each jurisdiction.
13 Operating income before taxes represents adj usted operating
14 revenues less all adj usted operating expenses treated
15 heretofore with the exception of deferred income taxes and
16 investment tax credits. Adj usted interest expense was
17 allocated by the combined rate base to develop net
18 operating income before taxes. As discussed earlier in
19 this testimony, subsequent additions to or deductions from
20 the respective tax bases were allocated to each
21 jurisdiction by aligning it with its causation or
22 fundamental association. In this manner, taxable income
23 for each jurisdiction was developed and the appropriate tax
24 rate was applied. Final tax amounts result after the
25 allocation of adj ustments and tax credits. All details
NOE, DI 22
Idaho Power Company
1 relating to the calculation of federal, Oregon, Idaho, and
2 other state income taxes are found on Tables 10, 11, and
3 12.
4 Q.Please describe Tables 13 through 15 of
5 Exhibit No. 26.
6 A.Tables 13 through 15 of Exhibit No. 26 list
7 the principal allocation factors used in the JSS and the
8 respective jurisdictional values for each allocation
9 factor. Table 15 lists the ratios of the principal
10 allocation factors included in Table 14.
11 Q.Please describe the development of the Idaho
12 jurisdictional revenue deficiency.
13 A.The summary of JSS results is presented on
14 pages 1 and 2 of Exhibit No. 26. The development of the
15 Idaho jurisdictional revenue deficiency is presented in the
16 column entitled "Idaho Retail" on page 1 of Exhibit No. 26.
17 The Idaho consolidated operating income of $148,675,968
18 (line 27 ) resulted in a return on rate base of 6.31 percent
19 (line 28). Based upon the Company's request for an overall
20 rate of return of 10.5 percent provided by Mr. Steve Keen,
21 the Company's Idaho jurisdictional net income should be
22 $192,477,554, as shown on line 33. The resulting earnings
23 deficiency is $43,801,586, as shown on line 34. Inclusion
24 of Construction Work in Progress allowed in the Company's
25 most recent rate case (Case No. IPC-E-08-10) of $6,520,122
NOE, DI 23
Idaho Power Company
1 as shown on line 35 increases the earnings deficiency to
2 $50,321,708, as shown on line 36.
3 Q.What net-to-gross or incremental income tax
4 factor did you use in developing the Idaho jurisdictional
5 revenue deficiency?
6 A.The composite incremental tax multiplier of
7 1.642 is the assimilation of the federal effective tax
8 rate, an Idaho composite tax rate, an Oregon composite tax
9 rate, and an additional state composite tax rate. This
10 value, as shown on line 38 of Exhibit No. 26, was provided
11 by the Company's tax department and is included in my
12 workpapers.
13 Q.What is the resulting Idaho jurisdictional
14 revenue deficiency?
15 A.The result of the Jurisdictional Separation
16 Study, as shown on page 1, line 39 of Exhibit No. 26,
17 indicates a total revenue deficiency of $82.6 million for
18 the Idaho retail jurisdiction. This represents a required
19 9.90 percent increase in normalized Idaho jurisdictional
20 revenues.
21 Q.Does this conclude your testimony?
22 A.Yes, it does.
23
24
25
NOE, DI 24
Idaho Power Company
RECEIVED
BEFORE THE 20" JUN - i PH 2: 44
ID/\HO PI.
IDAHO PUBLIC UTILITIES COMMISsrOtl:s co'\;: ¡ N
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
NOE, 01
TESTIMONY
EXHIBIT NO. 22
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Case No. IPC-E-11-08
K. Noe, IPC
Page 1 of2
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Exhibit No. 22
Case No. IPC-E-11-08
K. Noe, IPC
Page 2 of2
'i ~.. å ~~i~le- 0 Q) ø::....O:a.
RECEIVED
BEFORE THE 261\ JUN -I PM 2: 46
i \ t2\~il~\YA;'S~,;j, :Š S i 0 N
IDAHO PUBLIC UTILITIES COMMISSldNI \ç.,; V~,,",..
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
NOE, 01
TESTIMONY
EXHIBIT NO. 23
Idaho Power Company
Depreciation & Amortization Annualizing Adjustments
Estimated 2011
Annualized Forecasted
Depreciation Depreciation Annualizing Reserve
Account Account Description Expense Expense Adjustment Adjustment
30 1 00 Organization
30200 Franchises and Consents 853,176.48 853,176.48
30300 Miscellaneous Intan9ible Plant 6,378,354.24 6,188,898.97 189,455.27 94,727.63
TOTAL INTANGIBLE PLANT- AMORT 7,231,530.72 7,042,075.45 189,455.27 94,727.63
31020 Land and Land Ri9hts 8,268.36 8,268.36
31100 Structures and Improvements 2,152,401.96 2,144,648.26 7,753.70 3,876.85
31200 Boiler Plant Equipment 11,830,485.84 11,639,056.43 '191,429.41 95,714.71
31400 Turbogenerator Units 3,891,755.76 3,826,824.57 64,931.19 32,465.59
31500 Accesory electric Equipment 809,497.68 810,840.18 (1,342.50)(671.25)
31600 Misc Power Plant Equipment 506,930.28 505,200.23 1,730.05 865.02
TOTAL STEAM PRODUCTION PLANT 19,199,339.68 18,934,838.03 264,501.85 132,250.92
33000 Land and Land Ri9hts
33100 Strctures and Improvements 4,098,214.44 4.070,4 70.91 27,743.53 13,871.76
33200 Reservoirs, Dams, Waterways 5,652.985.56 5,638,735.96 14,249.60 7,124.80
33300 Waterweel, Turbines, Generato 3,698,414.28 3,690,360.72 8,053.56 4,026.78
33400 Accessory Electrc Equipment 1,340,542.20 1,328,437.51 12,104.69 6,052.35
33500 Misc Power Plant Equipment 492,998.88 482,276.90 10,721.98 5,360.99
33600 Roads, Railroads and Bridges 145,321.08 145,321.08
TOTAL HYDRO PRODUCTION PLANT 15,428,476.44 15,355,603.08 72,873.36 38,436.68
34000 LAND AND LAND RIGHTS
34100 Structures and Improvements 221,232.60 220,768.69 463.91 231.95
34200 Fuel Holders, Producers, Acces 121,639.20 121,387.15 252.05 126.3
34300 Prime Movers 3,267,119.28 3,260,866.96 6,252.32 3,126.16
34400 Generators 946,997.52 945,040.88 1,956,64 978.32
34500 Accessory Electric Equipment 808,401.96 806,742.67 1,659.29 829.65
34600 Misc Power Plant Equipment 78,931.80 78,770.33 161.47 80.73
TOTAL OTHER PRODUCTION PLANT 5,444,322.36 5,433,576.68 10,745.68 5,372.84
35020 Land and Land Ri9hts 455,047.20 455,047.20 .
35200 Structures and Improvements 954,983.40 946,120.72 8,862.68 4,431.34
35300 Station Equipment 7,369,784.28 7,299,356.34 70,425.94 35,212.97
35400 Towers and Fixtures 2.940,288.36 2,878,883.18 61,405.18 30,702.59
35500 Poles and FiX1ures 2,899,667.28 2,873,489.03 26,178.25 13,089.13
35600 Overhead Conductors, Devices 3,322,211.40 3,260,317.70 41,893.70 20,946.85
35900 Roads and Trails 3,132.60 3,132.60
TOTAL TRANSMISSION PLANT 17,945,114.52 17.736,348.77 208.765.75 104,382.88
36000 Land and Land Rights
36100 Strctures and improvements 593,227.56 566,603.00 26,624.56 13,312.28
36200 Station Equipment 3,664,705.92 3,552,727.22 111,978.70 55,989.35
TOTAL SUBSTATION EQUIPMENT 4,257,933.48 4,119,330.22 138,603.26 69,301.63
36400 Poles, Towers and FiX1ures 7,653,064.92 7,521,720.04 131,344.88 65,672.44
36500 Overhead Conductors, Devices 3,677,442.12 3,608,869.64 68,5n.48 34,286.24
36600 Underground Conduit 982,581.24 963,045.13 19,536.11 9,768.05
36700 Underground Conductors, Device 3,909,246.84 3,839,295.32 69,951.52 34,975.76
36800 Line Transformers 7,106,084.88 7,012,924.70 93,160.18 46,580.09
36900 Services 1 ,829,4 75.24 1,803,191.83 26,283.41 13,141.70
37000 Meters 1,024,934.76 1,029,540.33 (4,605.57)(2,302.79)
37010 Meters - AMI 3,677,844.60 3,226, n7.28 451,117.32 225,558.66
37030 Meters-Non AMI - Idaho 10.551,35.52 10,551,353.52
37100 installations, Cust Premises 29,256.24 28,967.40 288.84 144.42
37300 Street Lighting, Signal System 179,432.76 179,067.89 364.87 182.43
TOTAL DISTRIBUTION LINES 40,620,717.12 39,764,703.08 856,014.04 428,007.00
38900 Land and Land Rights
39000 Strctures and Improvements 1,954,946.04 1,898,283.28 56,662.76 28,331.38
39100 Offce Furniture, Equipment 7,851,477.00 7,417,941.94 433,535.06 216,767.53
39200 Transporttion Equipment 2,219,319.00 2,224,286.19 3,097.09
39300 Stores Equipment 85,303.92 81,344.93 3.958.99 1,979.50
39400 Tools, Shop, Garage Equipment 283,465.32 276,174.82 7,290.50 3,645.25
39500 Laboratory Equipment 684,507.60 664,858.21 19,649.39 9,824.70
39600 Powr Operated Equipment 676,137.60 681,232.n 10,005.41
39700 Communication Equipment 2,308,200.24 2,177,302.13 130,898.11 65.449.05
39800 Miscellaneous Equipment 505,034.16 483,371.42 21,682.74 10,831.37
TOTAL GENERAL EQUIPMENT PLANT 16,568,390.88 15,904,795.64 673,657.55 349,931.28
DEPR ON ELECTRIC PLANT IN SERVICE 119,464,294.68 117,249,195.50 2,225,161.49 1,125.683.23
Amortzation of Disallowed Costs (296,299.32)(296,299.32)
TOTAL DEPRECIATION & AMORTIZATION 126,399,526.08 123,994,971.63 2,414,616.76 1,220,410.86
Account 312.300 (108,264.n)(108,264.n)
Account 392 (1,996,903.08)(2,001.870.27)
Account 396 (676,137.60)(681,232.72)
Accunt 397.3.00 (272,780.88)(272,780.88)
Account 403 and 404 123.345,439.80 120,930,823.04
Exhibit No. 23
Case No. IPC-E-11-08
K. Noe,lPC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
NOE,OI
TESTIMONY
EXHIBIT NO. 24
Line
No.
1
2
3
Idaho Power Company
Summary of Payroll-Related Annualizing Adjustments
Operating Expenses
Source
Page
A Operating Payroll - Annualizing Adjustment
A 2012 Salary Structure Adjustment
Total Adjustments
(1 )
Amount
$1,955,023
2,377,859
$4,332,883
Exhibit No. 24
Case NO.IPC-E-11-08
K. Noe, IPC
Page 1 of4
Idaho Power Company A
Detail of Adjusents to 2011
Operang Exense
(1)
Line Source
No.Page Amount
1) Operating Payroll (Various aee)
1 Actual Total Year 2010 ST Payroll 148,290,903
2 Actual December 2010 ST Payroll 11,597,700
3 Annualized December 2010 (Dec times 13)x 13 150,770,100
4 Increase Over 2010 Actual 2,479,197
5 O&M Percentage 56.94%
6 Annualized December 2010 O&M ST payroll 1,411,696
7 2 Benefit Loading Percent 38.49%
8 Annualized December 2010 O&M ST w/Loading $1,955,023
2) 2012 Operating Payroll SSA (Various accts)
9 A Annualized December 2011 ST Payroll $150,770,100
10 2012 Structured Salary Adjustment 2.00%3,015,402
11 O&M Percentage 56.94%
12 O&M Wages Subject to Benefit Loading 1,717,020
13 2 Benefit Loading Percent 38.49%
14 Adjustment to Operating Expense $2,377,859
Exhibit No. 24
Case No. IPC-E-11-08
K. Noe, IPC
Page 2 of4
2010 ACTUAL for 111 - STRAIGHT TIME PAYROLL
By Account and Month
1-0&M 2 - Construction 3 - Other 242 Accunts Total
Jan,10 5,975,138 2,317,295 619,235 2,336,499 11,248,167
Feb,10 6,886,441 2,456,548 674,713 1,247,658 11,265,360
Mar,10 6,993,988 2,668,028 783,769 873,689 11,319,474
Apr,10 10,240,878 4,085,596 1,158,527 1,549,690 17,034,691
May,10 6,740,251 2,860,903 759,472 969,453 11,330,080
Jun,10 6,378,187 2,476,442 750,529 1,748,816 11,353,974
Jul,10 6,142,794 2,626,590 714,893 1,934,182 11,418,459
Aug,10 6,449,934 2,827,369 743,320 1,425,098 11,445,720
Sep,10 6,341,582 2,757,785 689,240 1,683,077 11,471,683
Oct, 10 10,076,022 4,411,723 1,119,403 1,641,380 17,248,527
Nov,10 5,898,392 2,566,563 659,597 2,432,516 11,557,068
Dec,10 6,315,709 2,918,80 741,521 1,621,990 11,597,700
84,439,315 34,973,323 9,414,219 19,464,046 148,290,903
% of Total 56.94%23.58%6.35%13.13%100.00%
Annualized December (x 13)150,770,100
Annualized Payroll Growth Factor 1.67%
Source Page 1
Exhibit No. 24
Case No. IPC-E-11-08
K. Noe, IPC
Page 3 of4
2010 Actual Benefits Loading %Source Page 2
Feb-11
7,131,983111 - STRAIGHT TIME PAYROLL
131 -INDIRECT BENEFIT LOADING 2,068,045 29.00%
140 - TAXES-EMPLOYER PAID 676,882 9.49%
Subtotal loading 2,744,926 38.49%
Exhibit No. 24
Case No. IPC-E-11-08
K. Noe, IPC
Page 4 of4
RECEIVED
BEFORE THE ZOO JUN -1 PM 2: 46
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IDAHO PUBLIC UTILITIES COMMISSION'IT:.s
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IDAHO POWER COMPANY
NOE, 01
TESTIMONY
EXHIBIT NO. 25
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IDAHO PUBLIC UTILITIES COMMìs\S~ì()N
CASE NO. IPC-E-11-08
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NOE, 01
TESTIMONY
EXHIBIT NO. 26
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Exhibit No. 26
Case No. IPC-E-11-08
K. Noe, IPC
Page 2 of 35
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Case No. IPC-E-11-08
K. Noe, fPC
Page 23 of 35
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Case NO.IPC-E-11-08
K. Noe, IPC
Page 25 of 35
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