20220630Appendix 7.3 - Class COS Process Guide.pdf

Appendix 7.3 – Class COS Process Guide
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Appendix 7.3 – Class Cost-of-Service Process Guide

To help support the evaluation of the Class Cost-of-Service Process Guide, Idaho Power
Company began with the guide previously provided as Larkin DI Testimony Exhibit No.
30 in IPC-E-11-08, Idaho Power Company’s last rate case. The process guide is
unchanged except to highlight new methodology since the 2011 rate case. All additions
are denoted by two asterisks (**) at the start and end of the addition with added text in
italicized, bold font.

The following is a technical description of Idaho Power Company’s Class Cost of Service
study. The methodology for separating costs among classes consists of a three-step
process generally referred to as classification, functionalization, and allocation. In all three
steps, recognition is given to the way in which the costs are incurred by relating these
costs to the way in which the utility is operated to provide electrical service.

I. PROCESS OVERVIEW

A. Classification

The Electric Utility Cost Allocation Manual, published in January of 1992 by the National
Association of Regulatory Utility Commissioners, serves as the basis for the Company’s
classification process. Classification refers to the identification of a cost as being either
customer-related, demand-related, or energy-related. These three cost components are
used to reflect the fact that an electric utility makes service available to customers on a
continuous basis, provides as much service, or capacity, as the customer desires at any
point in time, and supplies energy, which provides the customer the ability to do useful
work over an extended period of time. These three concepts of availability, capacity, and
energy are related to the three components of cost designated as customer, demand,
and energy components, respectively. In order to classify a particular cost by component,
primary attention is given to whether the cost varies as a result of changes in the number
of customers, changes in demand imposed by the customers, or changes in energy used
by the customers.

Examples of customer-related costs are the plant investments and expenses that are
associated with meters and service drops, meter reading, billing and collection, and
customer information and services as well as a portion of the investment in the distribution
system. These investments and expenses are made and incurred based on the number
of customers, regardless of the amount of energy used, and are therefore generally
considered to be fixed costs. Demand-related costs are investments in generation,
transmission, and a portion of the distribution plant and the associated operation and
maintenance expenses necessary to accommodate the maximum demand imposed on
the Company’s system. Energy-related costs are generally the variable costs associated

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with the operation of the generating plants, such as fuel. However, due to the hydro
production capability of the Company, a portion of the hydro and thermal generating plant
investment has historically been classified as energy-related.

B. Functionalization

In addition to classification, costs must be functionalized; that is, identified with utility
operating functions. Operating functions recognize the different roles played by the
various facilities in the electric utility system. In the Company’s accounts, these various
roles are already recognized to some degree, particularly in the recording of plant costs
as production-, transmission-, or distribution-related. However, this functional breakdown
is not in sufficient detail for cost-of-service purposes. Individual plant items are examined
and, where possible, the associated investment costs are assigned to one or more
operating functions, such as substations, primary lines, secondary lines and meters. This
level of functionalization allows costs to be more equitably allocated among classes of
customers.

C. Allocation and Summarization of Results

Once costs have been classified and functionalized, they are allocated to rate classes
based on the appropriate allocation factors. After individual costs have been allocated to
the various classes of service, it is possible to total these costs as allocated and arrive at
a breakdown of utility rate base and expenses by class. The results are stated in a
summary form to measure adequacy of revenues for each class. The measure of
adequacy is typically the rate of return earned on rate base compared to the requested
rate of return.

II. ASSIGN MODULE AND FUNCTIONALIZED COST MODULE

The class cost-of-service model is comprised of two separate Microsoft Excel workbooks.
The first workbook, called the Assign Module, performs the previously described
classification and functionalization processes. This workbook categorizes the Idaho
jurisdictional costs identified by FERC account into operating functions, such as
production, transmission, distribution, metering, customer service, etc. It also categorizes
the functional costs into demand-, energy-, and customer-related classifications. For
example, the Assign Module categorizes the Company’s investment in steam plant into
the production function and the demand- and energy-related classifications.

The second workbook, called the Functionalized Cost Module, or “FC Module” for short,
performs the class allocation process. This module allocates the classified and
functionalized costs developed in the Assign Module to the various customer classes.
For example, the FC Module allocates the demand- and energy-related production costs

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identified in the Assign Module to each of the Company’s customer classes and special
contract customers. Each of the major operations performed by this module is shown as
a separate worksheet to make the allocation process transparent and easy to understand.

III. CLASSIFICATION

A. Steam and Hydro Production

In the class cost-of-service study all steam and hydro production plants have been
classified on a demand and energy basis using the methodology preferred by the Idaho
Public Utilities Commission in prior general rate proceedings. The energy portion of the
steam and hydro production investment has been determined by use of the Idaho
jurisdictional load factor. By application of the load factor ratio to the steam and hydro
production plant investment, the energy-related portion is easily determined. The balance
of the steam and hydro production plant investment is then classified as demand-related.
All other production and transmission plants have been classified as demand-related.

**One update from the Company’s 2011 rate case is the addition of the Langley
production plant, which is considered baseload production similar to steam
production plants, thus it is classified with the same demand and energy allocation
as steam production plants. For classification of costs related to all natural gas-
fired production plants, a new allocation factor was developed reflecting the
weighting of all gas-fired production.**

B. PURPA and Purchased Power Expenses

PURPA and purchased power expenses booked to FERC Account 555 are classified as
demand-and energy-related in the same manner as steam and hydro generation plant.
Under the previous approach of classifying these expenses as energy only, customers
who use a larger proportion of energy with respect to their demand (higher load factors)
receive a greater allocation of these expenses than would have occurred if a power plant
had been constructed to serve the same loads. For example, if the Company had chosen
to build and operate a power plant to serve the same customer loads served by purchased
power, the plant would have been classified as both demand and energy. With that said,
it is reasonable to classify these expenses as demand- and energy-related in the same
manner as the Company’s steam and hydro generation plant. Under this methodology,
PURPA and purchased power expenses are classified according to the same ratio of
demand to energy used in the classification of hydro and steam generation plant.

C. Distribution Plant

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Distribution substation plant Accounts 360, 361, and 362 are classified as demand-
related. Distribution plant Accounts 364, 365, 366, 367, and 368 are classified as either
demand-related or customer-related using the same fixed and variable ratio computation
method utilized in the Company’s prior general rate case proceedings. The fixed to
variable ratio is updated according to a system capacity utilization measurement based
on a three-year average load duration curve.

IV. FUNCTIONALIZATION

A. General Plant

General plant is functionalized based on total production, transmission, and distribution
plant. As a result, a portion of general plant is assigned to each production, transmission,
and distribution function based on each function’s proportion to the total.

B. Accumulated Provision for Depreciation

The accumulated provision for depreciation is functionalized using the resulting
functionalization of costs for the appropriate plant item. For example, the accumulated
depreciation for steam production plant shown is functionalized based on the
functionalization of steam production plant in service.

C. Additions to and Reductions from Rate Base

Deductions from rate base include customer advances for construction and accumulated
deferred income taxes. Customer advances are functionalized based on the distribution
plant investment against which the advances apply. Accumulated deferred taxes are
functionalized based on total plant investment. Additions to rate base consist of fuel
inventory, which is functionalized based on energy production, and materials and
supplies, which are functionalized based on the appropriate plant function. Deferred
conservation expenses are functionalized based on the Idaho jurisdictional load factor
resulting in a specific percentage of the deferred expenses being functionalized to energy
production and the remainder being functionalized to demand production.

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D. Other Operating Revenue

Other operating revenue is functionalized based on either the functionalization of the
related rate base item or, in the situation where a particular revenue item may be identified
with a specific service, the functionalization of the specific service item.

E. O&M Expense

In general, the basis for the functionalization of O&M expense is the same as that for the
associated plant.

F. Labor Components

For each applicable expense account in each functional group, the labor component is
separately functionalized. For example, for Account 535 the labor-related supervision and
engineering expense is functionalized based on the cumulative labor as functionalized for
Accounts 536 through 540. In a similar fashion, the allocation of supervision and
engineering associated with hydraulic maintenance expense, Account 541, is based on
the composite labor expense for Accounts 542 through 545. Total functionalized labor
expense serves the additional purpose of functionalizing employee pensions and other
labor-related taxes and expenses.

G. Depreciation Expense, Taxes Other than Income, and Income Taxes

Depreciation expense is functionalized based on the function of the associated plant.
Taxes other than income are also functionalized based on the function of the source of
the tax. Deferred income taxes are functionalized based on plant investment. The
functionalization of federal and state income taxes is based on the functionalization of
total rate base and expenses.

V. ALLOCATION

A. Derivation of Peak Demands

For customers taking service through interval meters, system coincident demands are
taken directly from their meter read data. For all other customers coincident demands are
estimated through the use of system coincident demand factors. These factors are
defined as the ratio of the system coincident demand to the population’s average demand.
To determine the monthly system coincident peak demands by rate class, each class’s
monthly system coincident demand factors from the load research sample are applied to
the test year monthly average demand values for each class. Similarly, a non-coincident
(or “group”) demand factor is defined as the ratio of a population’s non-coincident peak

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demand to the population’s average demand. To determine the monthly non-coincident
peak demands by rate class, each class’s monthly non-coincident demand factors from
the load research sample are applied to the test year monthly average demand values
for each class.

Customers are billed throughout each month and billing periods, or cycles, typically
include portions of more than one calendar month. Billing period data is converted into
calendar month data using a nonlinear method based on load research data that utilizes
actual daily usage patterns. Total daily consumption is assumed to fluctuate in proportion
to the fluctuations in the daily consumption of the load research sample customers. This
methodology captures the effects of weather on energy consumption and improves the
process of determining coincident peak demand responsibility.

**System coincident peak demand allocates capacity costs required to serve
Residential and Small General Service on-site generation customers drawing
energy, and requires modification to the derivation of peak demand. For each of
the two studies, Idaho Power utilized the respective measurement interval, hourly
netted energy, or real-time delivered energy for Residential and Small Generation
Service on-site generation customers to reflect the load service provided by Idaho
Power at the time of system peak. Because the value for Residential and Small
General on-site generation will be established independently through this docket,
this adjustment is necessary to avoid the double counting of benefits related to
excess generation at the time of system peak.**

B. Marginal Cost Usage

While the 3CP/12CP methodology eliminates the need for marginal cost weighting in the
allocation of production plant costs, this weighting is still necessary to properly
seasonalize energy- and transmission-related costs. The use of marginal cost weighting
strikes a balance between backward-looking costs already incurred and forward-looking
costs to be incurred in the future, and injects into the allocation process recognition of the
influence seasonal load profiles have on cost causation.

The marginal costs associated with new resource integration are seasonalized based on
the monthly peak-hour generation deficiencies which the Company expects to encounter
during the next five years of the planning period based on the 90th percentile water and
70th percentile load criteria used for planning purposes. The relative sizes of the five-year
average monthly peak-hour deficiencies identified in the IRP are used to define the share
of the annual capacity cost assigned to each month. The marginal costs associated with
planned system expansions are seasonalized based on the monthly share of projected
peak-hour load growth. The total demand-related transmission marginal costs for each

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month are then derived by adding the monthly values for both categories of transmission
costs.

Updated marginal energy costs are calculated by quantifying the difference in net power
supply costs resulting from the addition of 50 megawatts of load to all hours of the
Company’s base case system simulation run for the five-year planning period. It should
be noted that the marginal costs have been used solely for purposes of developing
allocation factors and not for purposes of developing the Company’s revenue
requirement.

C. Production Plant Cost Allocation

The class cost-of-service study allocates the costs of the Company’s generation peaking
facilities differently than its base-load resources. Rather than allocating all production
plant based on the same allocation factor, this method allocates production plant costs
based on the nature of the load being served. Under this approach, production plant
costs associated with serving summer peak load are allocated separately from costs
associated with serving the base and intermediate load. That is, the costs associated with
building and operating combustion turbines, which are used primarily to serve summer
peak loads, have been allocated to customers differently than the costs associated with
the Company’s other generation resources. This method allocates production plant costs
associated with serving base and intermediate load using an average of 12 monthly
coincident demands (“12CP”), without marginal cost weighting. Using an un-weighted
12CP allocator is appropriate in this case given that fixed base and intermediate
generation costs do not vary greatly between the summer and non-summer seasons.
Furthermore, the study allocates fixed generation costs associated with serving peak load
using an average of the three coincident peak demands (“3CP”) occurring in June, July,
and August. This method of allocation isolates the costs associated with peaking
resources and allocates those costs according to the load that is causing the investment.

The cost allocation method used in the study is based on the concept that the costs
associated with each of the Company’s generation resources can be categorized
according to the type of loads being served. Utilities typically experience three distinct
time-based production costing periods that are driven by customer loads. The costing
periods are normally identified as base, intermediate, and peak. The base period is
equivalent to a low load or off-peak time period where loads are at the lowest, normally
during the nighttime hours. The intermediate time period represents the shoulder hours
which are driven by the mid-peak loads that typically occur throughout the winter daytime
and in the early morning and late evening during the summer months. The peak category
is driven by the peak loads that occur during summer afternoons and evenings. The base
and intermediate loads on the Company’s system are typically served by the same
generation resources. In recognition of that fact, those two categories have been

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combined for cost allocation purposes. The generation resources that serve the peak
loads, i.e., combustion turbines, are normally only utilized for that single purpose.
Consistent with that concept, the costs associated with peak-related resources have been
segmented into a second category for cost allocation purposes. Using this methodology
there is no need for marginal cost weighting because the seasonal nature of the loads is
reflected in the allocation factors.

The production plant costs that have been classified as serving base and intermediate
load are captured in Accounts 310-316, Steam Production, and Accounts 330-336,
Hydraulic Production. The costs identified under the Steam Production category
represent the Company’s investment in coal-fired generation facilities, and the costs
identified under the Hydraulic Production category represent the Company’s investment
in its hydroelectric generation facilities.

Utilities typically utilize their generation resources to serve customer loads by operating
the resources with the lowest operating cost first and as demand grows more costly
resources are then dispatched. This is no different for Idaho Power. However, since
hydroelectric generation is such a significant portion of the Company’s resource stack,
stream flow conditions and economics can influence the proportionate share of output
provided by steam and hydro resources throughout the year. Since hydroelectric output
is highly dependent upon stream flows, steam production is ramped up or down according
to the production capability of the hydro. Therefore, throughout the year, hydro and steam
production plants are utilized at varying proportions to serve base and intermediate loads
according to the production capabilities of the hydro plants. However, the combined
monthly output of these two resource types does not vary significantly between the
summer and non-summer months as does the output of the combustion turbines.

Accounts 340-346, Other Production, contain the Company’s investment in gas-fueled
production plant. The production plant investment captured in Accounts 340-346
represents the Company’s investment in the combustion turbine generation facilities.
**For this study, Bennett Mountain and Danskin power plants are identified as
being** used to serve peak demands, **and the Company’s Langley production
resource is considered a baseload resource. The Company, in the Idaho Results of
Operations, has provided Accounts 340-346 values for Langley and peaking plants
separately to allow for independent allocation of costs.** The investment identified
as peaking plant is the investment in combustion turbine generation resources that were
constructed specifically to meet the summer peak loads.

In the Functionalized Cost Module, the names “D10BS” and “D10BNS” describe the
factors used to allocate the production plant associated with serving the base and
intermediate loads. The name “D10P” is used to describe the allocation factor used to
allocate the production plant associated with serving the peak loads. The D10BS and

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D10BNS represent the non-weighted average twelve coincident peak demands for the
summer and non-summer seasons respectively. The allocator D10P represents the non-
weighted average three coincident peak demands for the summer months of June, July,
and August.

D. Transmission and Distribution Cost Allocation

The Company’s approach to cost allocation for transmission and distribution facilities is
an effective method for equitably assigning costs to customer classes. Under this method,
transmission and distribution costs are properly segmented according to the manner in
which the costs are imposed on the system. As a result, the cost responsibility of each
class can be effectively identified through a combination of direct cost assignment and
cost allocation based on the appropriate demand- or customer-based factors.

The allocation factor D13 is used to allocate transmission costs to customer classes. The
first step in deriving this factor is to calculate ratios based on the sum of the actual
coincident peak demands for each customer class. Second, weighted coincident peak
demand values are derived by multiplying the actual monthly coincident peak demands
by the monthly transmission marginal costs. Corresponding weighted ratios are then
calculated for each customer class. Finally, the actual ratios are averaged with the
weighted ratios to derive the non-seasonalized transmission allocation factor D13. The
Company applies this “averaging approach” as a rate stability measure intended to
mitigate any extreme impacts that the marginal costs may have on cost allocation.

The capacity components of distribution plant, both primary and secondary, are allocated
by the non-coincident group peak demands for each customer class identified as demand
allocation factors D20, D30, D50, and D60.

**The capacity components of distribution plant required to serve Residential and
Small General on-site generation customers includes recognition of the bi-
directional use of distribution plant to receive and export energy. To evaluate bi-
directional capacity requirements, the Residential and Small General on-site
generation customers’ demand values were evaluated in two manners to
correspond to the associated measurement interval, hourly netting, and real-time
measurement. For hourly netting, any customer demand value with a negative
value at the time of non-coincident group peak was converted to an absolute value.
This adjustment recognizes the bi-directional use of the distribution system and
creates an allocation factor independent if energy is being consumed or sent to the
grid. For real-time measurement, a comparison between the real time delivered and
received channels was completed with the maximum value in the hour is used to
derive the non-coincident group peak demand.**

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The customer components of distribution plant, both primary and secondary, are allocated
by the average number of customers identified as customer allocation factors C20, C30,
C50 and C60.

E. Energy-Related Cost Allocation

The energy-related cost allocators, E10S and E10NS, are derived by averaging the
normalized energy values for each customer class with the normalized energy values
weighted by the marginal energy costs. First, summer and non-summer ratios based on
each class’s proportionate share of the total normalized energy usage for the test year
are determined. Next, summer and non-summer ratios based on the monthly normalized
energy usage for each customer class weighted by the monthly marginal cost are
calculated. Finally, these two values are averaged, resulting in the E10S and E10NS
allocators used in this study. This averaging approach is consistent with the methodology
used in the derivation of the demand-related allocation factor D13.

**Normalized energy values for the Residential and Small General on-site
generation customer classes are the energy recorded either under the hourly
netting measurement interval, or the real time delivered channel for each
respective study. The value for Residential and Small General on-site generation
delivered to Idaho Power for both the hourly netting measurement interval, and the
real-time measurement interval will be established independently through this
docket.**

F. Customer Accounting and Customer Assistance Expense Allocation

The principal customer accounting expenses which require allocation are meter reading
expenses, customer records and collections, and uncollectible accounts. The meter
reading and customer records and collection expenses are allocated based upon a review
of actual practices of the Company in reading meters and preparing monthly bills. The
allocation of uncollectible amounts is similarly based upon a review of actual Company
data. Customer assistance expenses are allocated based on the average number of
customers in each class.

G. State and Federal Income Tax Allocation

The state and federal income taxes for the Idaho jurisdiction are allocated to each
customer class and special contract customer according to each class’s allocated share
of rate base. Once the state and federal income taxes are allocated to each customer
class, they are functionalized based on the functionalization of total rate base and
expenses for each class.

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VI. REVENUE REQUIREMENT AND APPLICATION

Once all costs have been properly functionalized, classified, and allocated, the Company
is able to determine the revenue requirement for each customer class. The sales revenue
required includes return on rate base, total operating expenses, and incremental taxes
computed using the net-to-gross multiplier.

**To match the FC Module’s Revenues from Rates with the Idaho Results of
Operations’ exclusion of Valmy levelized revenue, the FC Module includes an
adjustment to each class’s cost of service results to add back each plant’s
levelized revenue requirement. Derivation of allocation to each class followed
established Assign Module classification and functionalization methodology for
each plant. To allocate production baseload demand and energy to each class,
established FC Module allocation factors were utilized.**