20221026Appendix 7.1 Idaho ROO Process Guide.pdf

Appendix 7.1 – Idaho ROO Process Guide
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Appendix 7.1 – Idaho 2021 Results of Operations Process Guide

The 2021 Results of Operations (“ROO”) study, 12-months ending December 31, 2021,
was developed using a methodology similar to that approved in the Company’s last
general rate case, Case No. IPC-E-11-08 (“2011 rate case”). However, unlike the 2011
rate case, no financial data was grown or forecasted. Because the purpose of this study
is to serve as the basis for a class cost-of-service study, this study does not include a
requested rate of return. Rather, the return component included in the ROO study
represents the difference between 2021 normalized revenues and the 2021 cost-of-
service components. The following summarizes the process Idaho Power Company
(“Idaho Power” or “Company”) undertook for the completion of the jurisdictional
separation study (“JSS”) for the 12-months ending December 31, 2021:

 The Company began with actual, audited and reported to the U.S. Securities and
Exchange Commission, 2021 financial data (“2021 Actuals”) including (1) other
operating revenues, (2) other revenues and expenses, (3) operation and
maintenance (“O&M”) expenses, (4) property insurance expenses, (5) regulatory
commission expenses, (6) depreciation and amortization expense, (7) electric
plant/regulatory assets – amortizations, adjustments, gains, and losses, (8)
regulatory debits and credits, (9) taxes other than income taxes, (10) Idaho Energy
Resources Company’s (“IERCo”) statement of income and rate base components,
(11) allowance for funds used during construction (“AFUDC”) related to the Hells
Canyon relicensing, (12) electric plant in service and related items, (13) materials
and supplies, (14) other deferred programs, (15) plant held for future use, (16)
accumulated deferred income taxes, and (17) customer advances for construction.

 Next the Company made standard regulatory adjustments, or adjustments in
conformance with prior Idaho Public Utilities Commission (“Commission”) orders,
to the 2021 Actuals. The adjustments, which are explained and quantified in
further detail below, included the removal of:

o general advertising expenses,
o specific memberships and contributions,
o prepayments,
o a portion of incentive compensation,
o financial impacts of the Idaho and Oregon Energy Efficiency Rider revenues
and expenses, and
o plant held for future use to remove structures and specific properties for
which the future use is uncertain.

 In addition, Idaho Power adjusted the 2021 Actuals to reflect updated normalized
power supply expenses (“NPSE”). Normalized or base NPSE is calculated by
modeling the test period under multiple historical water conditions; in this case, the
Company modeled 67 historical water conditions (1954-2021). The term “net
power supply expense” refers to the sum of the following Federal Energy
Regulatory Commission (“FERC”) accounts: fuel expense (FERC Accounts 501
Appendix 7.1 – Idaho ROO Process Guide
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and 547), and purchased power expenses (FERC Account 555), minus surplus
sales revenues (FERC Account 447).

The Company modeled NPSE using the AURORA model, which is a
comprehensive electric resource dispatch model that simulates the economic
dispatch of the Company’s resources to determine NPSE. The Commission has
accepted the use of AURORA to determine base level NPSE for general rate cases
or other one off base level NPSE update filings (most recently, Case No. IPC-E-
13-20), marginal cost analyses, and resource modeling for the Company’s
Integrated Resource Plan. In modeling NPSE in AURORA, the Company updated
a number of input variables including fuel prices, transportation costs, heat rates,
forced outage rates, planned outages, normalized load and sales, contracts for
wholesale power and power purchases and sales, Public Utility Regulatory Policies
Act contract expenses, and wheeling expenses.

 Because the Company has an established recovery mechanism in place for the
Valmy coal-fired plant, Idaho Power has removed all cost-of-service components
associated with this coal plant that is recovered through the levelized revenue
requirement mechanism. Recognition of the Valmy related levelized revenue
requirement is applied as an adjustment to the class cost-of-service process as
described in Appendix 7.3.

 Finally, annualizing adjustments were made.

The financial data is then input into the JSS to determine the Idaho jurisdictional ROO.
The resulting JSS is included as Appendix 7.2. The JSS is a three-step process - the
classification, functionalization, and allocation of costs - that separates costs among
jurisdictions. In all three steps, recognition is given to the way in which costs are incurred
by relating these costs to utility operations.

Classification groups the costs into three categories: demand-related, energy-related,
and customer-related. Costs are also functionalized, or identified as generation,
transmission, and distribution operating functions. Finally, the costs are allocated
between the Idaho and Oregon jurisdictions, apportioning the total system costs among
jurisdictions by introducing allocation factors. An allocation factor specifies the
jurisdictional value as a share or percent of the total system quantity.

The classification, functionalization, and allocation of costs was performed in accordance
with the approved 2011 rate case methodologies1. Once the individual accounts have
been allocated to the various jurisdictions, it is possible to summarize these into total
utility rate base and net income by jurisdiction. The results are stated in a summary form
and measure the difference between 2021 normalized revenues and the 2021 cost-of-
service components.

1 With the exception of Electric Plant-in-Service FERC Account 368 – Line Transformers, which was
allocated using the D60 allocator, distribution at generation level, as was approved in the last Oregon
general rate case, Case No. UE 233.
Appendix 7.1 – Idaho ROO Process Guide
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JURISDICTIONAL SEPARATION STUDY
FOR THE 12-MONTHS ENDING DECEMBER 31, 2021

The following is a description and quantification of adjustments made to 2021 Actuals in
the order they appear in the JSS and a brief description of how the adjusted 2021 Actuals
were allocated to each jurisdiction:

 The first adjustment, on line 78, adds to the Idaho jurisdictional earnings deficiency
$6,815,472, the level of recovery of AFUDC associated with the Hells Canyon
relicensing project construction work in progress originally approved in the
Company’s 2008 rate case (Case No. IPC-E-08-10) and again in the 2011 rate
case.

 Table 1 – Electric Plant-In-Service
o Table 1 reflects Idaho Power’s 13-month average electric plant-in-service
values, excluding Valmy and any remaining Boardman asset balances, at
December 31, 2021. No other adjustments or additions were made to
electric plant-in-service.
o Production plant was allocated to the jurisdictions based on the average of
the 12 monthly coincident peak demands and unless noted otherwise,
allocation of transmission and distribution plant was based on the same
methodology. Some transmission and distribution facilities were directly
assigned to the customers who paid upfront for the facilities installed to
serve them. General plant was allocated on the same basis as the sum of
the allocated investments in production, transmission, and distribution plant.

 Table 2 – Accumulated Provision for Depreciation
o Accumulated Provision for Depreciation is reflected as the 13-month
average at December 31, 2021. A reserve adjustment was made to reflect
half of the annualized depreciation expense adjustment that occurs in Table
6 and detailed below. The Accumulated Provision for Depreciation
balances exclude Valmy and any remaining Boardman values.
o The Accumulated Provision for Depreciation was allocated by total for each
production plant type and for each primary plant account in other functional
groups based on the related plant account in Table 1. Amortization of other
utility plant was functionalized then allocated based on the related plant
items in Table 1.

 Table 3 – Additions and Deletions to Rate Base

o Balances of customer advances for construction (FERC Account 252),
accumulated deferred income taxes (FERC Accounts 190, 282, and 283),
materials and supplies (FERC Accounts 154 and 163), and IERCo rate base
components reflect the 13-month average. However, other deferred
programs reflect the account balances as of December 31, 2021.
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o A number of adjustments are included in Table 3:

 Fuel stock inventory includes only required fuel stock inventory of
$29,293,629.

 Removal of the following from rate base:
 $24,557,592 in prepayments,
 $1,069,812 in plant held for future use for which the plant use
is uncertain at this time, the plant may be split, or for plant
structures that will be razed,
 $9,419,457 associated with the Siemen’s long-term program
contract regulatory asset that received deferred rate base
treatment with IPUC Order No. 33420, and
 $85,531 of plant that was determined in the 2011 rate case to
no longer be used and useful at the Bridger Coal plant.

o Additions and deletions to rate base were allocated under a number of
different methodologies: (1) customer advances for construction were
directly assigned to customers by jurisdiction, (2) accumulated deferred
income taxes are allocated by plant, customer advances for construction,
or labor, (3) materials and supplies by their respective plant allocators, (4)
fuel inventory on the basis of energy, (5) components of IERCo on energy,
and (6) Commission-ordered deferred investments were either directly
assigned to a specific jurisdiction or allocated based on energy.

 Table 4 – Operating Revenues
o Operating Revenues includes an adjustment of ($187,931,014) to 2021
Actuals to reflect the normalization and annualization of revenues and an
adjustment of ($48,845,418) for the removal of revenues associated with
the Valmy plant. In addition, an adjustment of ($65,077,513) to FERC
Account 447, Opportunity Sales, was made to reflect the normalized NPSE
results from AURORA. Finally, $29,920,448 associated with the Idaho and
Oregon Energy Efficiency Rider revenues was removed from FERC
Account 456, Other Electric Revenues.

o Operating Revenues were directly assigned to each jurisdiction.
Opportunity Sales are credited to each jurisdiction in proportion to
generation-level energy use. Other Operating Revenues were allocated in
a manner that offsets related allocations of rate base, or where a particular
revenue item could be associated with a specific jurisdiction, directly
assigned.

Appendix 7.1 – Idaho ROO Process Guide
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 Table 5 – Operations and Maintenance Expenses

o The following is a summary of the adjustments made to 2021 Actual O&M
expenses:

 An annualizing adjustment was made to operating payroll to reflect
as though the year-end amounts had been in existence for the entire
year,
 All 2021 actual non-fuel O&M attributable to the Valmy plant was
removed as the expenses are recovered through the Valmy levelized
revenue requirement mechanism,
 NPSE were updated to reflect normalized conditions from the
updated AURORA run,
 $29,920,448 in Idaho Energy Efficiency Rider expenses (FERC
Account 908) were removed,
 $7,636,409 of incentive expense (FERC Account 920) was removed
so that only the normalized incentive components that are
attributable to Customer Satisfaction and Reliability were included,
 $122,954 of property insurance expense associated with Valmy was
removed from FERC Account 924 as those expenses are recovered
through the Valmy levelized revenue requirement mechanism, and
 a deduction of $635,984 was made for general advertising expenses,
certain memberships and contributions, and miscellaneous other
expenses, consistent with the methodology approved in the 2011
rate case.
o The allocation of O&M expenses is detailed in Table 5. In general, the basis
for each allocation is identifiable with the source code listed in the JSS
provided as Appendix 7.2. Demands are identified by source code
beginning with the prefix “D”, energy use is identified by a source code
beginning with an “E” prefix, related plant is identified by a line number
source code, and customer-weighted allocation factors begin with a “CW”
prefix. For each functional group, the labor component was separately
allocated in accordance with the detail provided in Table 13 – Development
of Labor Related Allocator. Total allocated labor expense served the
additional purpose of allocating employee pension and other labor-related
taxes and expenses.

 Table 6 – Depreciation and Amortization Expense
o Annualizing adjustments were made to reflect depreciation and
amortization expense amounts as though they had been in existence for the
entire year.
o Depreciation and amortization expenses were identified by production plant
type or by primary plant account for other functional plant groups and
allocated consistent with the related plant account. Valmy and Boardman
depreciation and amortization expense were removed as amounts were
recovered through the levelized revenue requirement mechanisms.
Appendix 7.1 – Idaho ROO Process Guide
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 Table 7 – Taxes Other than Income Taxes
o Federal unemployment, Social Security, and state unemployment taxes are
eliminated by the state and federal payroll loading reversal. The expenses
are removed to demonstrate that these amounts are not double counted.
The hydro generation kilowatt-hour tax and irrigation tax refund expenses
are normalized.
o Individual taxes other than income tax items were allocated in a manner
consistent with the bases by which the respective taxes were assessed.

 Table 8 – Regulatory Debits and Credits
o No adjustment was made to 2021 Actuals.
o The amortization expense is assigned by jurisdiction for which the
regulatory debit or credit was established.

 Table 9 – Income Taxes: Federal, Oregon, Idaho, and Other State
o Normalized state and federal income tax liabilities are summarized on
Tables 9 through 12.
o The deferred income taxes and the investment tax credit adjustments were
allocated based on the Company’s plant investment and net income before
tax adjustments. The respective tax bases were developed and calculated
directly for each jurisdiction. Operating income before taxes represents
adjusted operating revenues less all adjusted operating expense with the
exception of deferred income taxes and investment tax credits. Adjusted
interest expense was allocated by the combined rate base to develop net
operating income before taxes. Subsequent additions to or deductions from
the respective tax bases were allocated to each jurisdiction by aligning it
with its causation or fundamental association, resulting in taxable income
for each jurisdiction. The appropriate tax rate was applied and the resulting
final tax amounts by jurisdiction derived.

 Tables 13 through 15 – Development of Labor Related Allocator, Allocation
Factors, and Allocation Factors - Ratios
o No adjustment was made to 2021 Actuals.
o The tables include the principal allocation factors used in the JSS and the
respective jurisdictional values for each allocation factor. Table 15 lists the
ratios of the principal allocation included in Table 14.

The summary of the JSS results are presented on page 1 of Appendix 7.2. The
development of the Idaho jurisdictional ROO is presented in the column entitled “Idaho
Retail”. When comparing the difference between 2021 normalized revenues and the
2021 cost-of-service components, the resulting Idaho consolidated operating income is
$190,831,772 (line 45).