20190930Motion to Accept Fixed Cost Report.pdf

LISA D. NORDSTROM (lSB No. 5733)
Idaho Power Company
1221West ldaho Street (83702)
P.O. Box 70
Boise, ldaho 83707
Telephone: [phone]
Facsimile: [phone]
lnordstrom@ idahopower. com
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Attorney for ldaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE PETITION OF
IDAHO POWER COMPANY TO STUDY
FIXED COSTS OF PROVIDING
ELECTRIC SERVICE TO CUSTOMERS
CASE NO. IPC-E-18-16
IDAHO POWER COMPANY'S
MOTION TO ACCEPT
FIXED COST REPORT
ldaho Power Company ("ldaho Power" or "Company"), in accordance with
Procedural Rule 056, hereby moves that the ldaho Public Utilities Commission
("Commission") issue an order accepting its Fixed Cost Report for filing in satisfaction of
its directive in Order No. 34046. This Motion is based on the following:
r. MoTroN
1. On May 9,2018, the Commission issued Order No.34046 in responseto
ldaho Power's Application for Authority to Establish New Schedules for Residential and
Small General Service Customers with On-Site Generation in Case No. IPC-E-17-13.
The Commission found that 'it is time for the Company to address fixed-cost
apportionment across its system" and:
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)
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IDAHO POWER COMPANY'S MOTION TO ACCEPT FIXED COST REPORT - 1
lT lS FURTHER ORDERED that ldaho Power shall file
a study with the Commission exploring fixed-cost recovery in
basic charges and other rate design options prior to its next
general rate case.
Order No. 34046 at 17 and 31.
2. On page 23 of Order No. 34046, the Commission stated that it was
"convinced" based upon evidence in the record of Case No. IPC-E-17-13 "that critical
questions related to fixed costs must be addressed." Due to the unclear timing of ldaho
Power's next general rate case, the Commission ordered the Company to undertake "a
comprehensive customer fixed-cost analysis to determine the proper methodology and
'spread' of fixed costs as they relate to the Company's customers."
3. The Commission directed that "the Company, with input from interested
parties, shall outline the scope of the study that should include exploring fixed-cost
recovery in basic charges and other rate design options." Order No. 34046 at23.
4. On November 9, 2018, the Commission issued a Notice of Petition and
lntervention Deadline. Order No. 34190. The Commission subsequently granted
intervention to the ldaho Conservation League, Avista Corporation, NW Energy Coalition,
ldaho lrrigation Pumpers Association, lnc., ldaHydro, Rocky Mountain Power, Vote Solar,
City of Boise City, ldaho Sierra Club, ldaho Clean Energy Association, ldaho lndustrial
Customers of ldaho Power, and Russell Schiermeier. Order Nos.34194, 34201, 34208,
34356, and 34360.
5. Over the course of nine months, ldaho Power, Commission Staff, and
lntervenors participated in one prehearing conference and five settlement workshops to
scope and discuss fixed cost issues pertaining to the Commission's fixed cost study
directive. With the feedback received, the Company prepared numerous analyses and
IDAHO POWER COMPANY'S MOTION TO ACCEPT FIXED COST REPORT - 2
incorporated resulting feedback into its Fixed Cost Report, included as Attachment 1 to
this Motion.
6. ldaho Power has interpreted the Commission's directive as seeking to
inform and educate on fixed cost methodologies and apportionment to customers through
rate design. Consequently, the Company makes no recommendations concerning
implementation of the rate designs discussed in its Fixed Cost Report at this time. While
it intends to propose rate modifications to address fixed cost issues when it files its next
general rate case, ldaho Power stands ready to make incremental changes in the interim
if directed by the Commission to do so.
il. coNcLUStoN
Having solicited stakeholder input and completing a fixed cost analysis, ldaho
Power respectfully requests the Commission accept for filing its Fixed Cost Report in
satisfaction of the Commission's directive in Order No. 34046.
DATED at Boise, ldaho, this 30th day of September 2019.
LISA D
Attorney for ldaho Power Company
IDAHO POWER COMPANY'S MOTION TO ACCEPT FIXED COST REPORT - 3
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 30th day of September 20191 served a true and
correct copy of IDAHO POWER COMPANY'S MOTION TO ACCEPT FIXED COST
REPORT upon the following named parties by the method indicated below, and
addressed to the following:
Commission Staff
Edward Jewell
Deputy Attorney General
ldaho Public Utilities Commission
11331 W. Chinden Blvd
Building 8, Suite 201-A (83714)
P.O. Box 83720
Boise, ldaho 83720-007 4
!daHydro
C. Tom Arkoosh
ARKOOSH LAW OFFICES
802 West Bannock Street, Suite LP 103
P.O. Box 2900
Boise, ldaho 83701
ldaho Conseruation League and NW
Energy Coalition
Benjamin J. Otto
ldaho Conservation League
710 North 6th Street
Boise, ldaho 83702
NW Energy Coalition
F. Diego Rivas
NW Energy Coalition
1 101 8th Avenue
Helena, Montana 59601
ldaho lrrigation Pumpers Association, lnc.
Eric L. Olsen
ECHO HAWK & OLSEN, PLLC
505 Pershing Avenue, Suite 100
P.O. Box 6119
Pocatello, ldaho 83205
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taylor.pestel h.com
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IDAHO POWER COMPANY'S MOTION TO ACCEPT FIXED COST REPORT - 4
Anthony Yankel
12700 Lake Avenue, Unit 2505
Lakewood, Ohio 44107
Vote Solar
Briana Kobor
Vote Solar
358 South 700 East, Suite 8206
Salt Lake City, Utah 84102
David Bender
Earthjustice
3916 Nakoma Road
Madison, Wisconsin 537 11
Al Luna
Nick Thorpe
1625 Massachusetts Avenue, NW, Suite 702
Washington, DC 20036
City of Boise
Abigail R. Germaine
Deputy City Attorney
Boise City Attorney's Office
150 North Capitol Boulevard
P.O. Box 500
Boise, ldaho 83701-0500
Idaho Clean Energy Association
Preston N. Carter
GIVENS PURSLEY LLP
601 West Bannock Street
Boise, ldaho 83702
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nthorpe@earthj ustice.org
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IDAHO POWER COMPANY'S MOTION TO ACCEPT FIXED COST REPORT - 5
Sierra Club
Kelsey Jae Nunez
KELSEY JAE NUNEZLLC
920 North Clover Drive
Boise, ldaho 83703
Zack Waterman
Michael Heckler
ldaho Sierra Club
503 West Franklin Street
Boise, ldaho 83702
Avista Corporation
David J. Meyer
Avista Corporation
1411 East Mission Avenue, MSC 27
P.O. Box 3727
Spokane, Wash i ngto n 99220-37 27
Patrick D. Ehrbar
Avista Corporation
1411 East Mission Avenue, MSC 27
P.O. Box 3727
Spokane, Wash i ngto n 99220-37 27
PacifiCorp d/b/a Rocky Mountain Power
Yvonne R. Hogle
Rocky Mountain Power
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
Ted Weston
Rocky Mountain Power
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
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michael.p [e-mail]
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ioe. m iller@avistacorp. com
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IDAHO POWER COMPANY'S MOTION TO ACCEPT FIXED COST REPORT - 6
lndustrial Customers of ldaho Power
Peter J. Richardson
RICHARDSON ADAMS, PLLC
515 North 27th Street (83702)
P.O. Box 7218
Boise, ldaho 83707
Dr. Don Reading
6070 Hill Road
Boise, ldaho 83703
lndividual
Russell Schiermeier
29393 Davis Road
Bruneau, ldaho 83604
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Ki berly Towel Executive Assistant
IDAHO POWER COMPANY'S MOTION TO ACCEPT FIXED COST REPORT - 7
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-1 g-1 6
IDAHO POWER COMPANY
ATTACHMENT 1
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lPc-E-18-16
Fixed Gost Report
September 2019
O Idaho Power
Table of Contents
TeeLe OF CoNTENTS
Table of Contents...............
List of Tables .....................
List of Figures ....................
List of Appendices
L Executive Summary.....
II. Background..................
IIL Rate Design Overview
IV. Class Cost of Service Process Overview
V. 2017 Class Cost of Service
A. Development of the 2017 CCOS
8.2017 CCOS Results..
C. Effectiveness of Existing Rate Designs to Collect Fixed Costs....
D. Potential Modifi cations to the CCOS Methodology.....................
CCOS Scenario No. 1
CCOS Scenario No. 2
CCOS Scenario No. 3
E. CCOS Conclusion
VI. Rate Design Analysis
A. Residential and Small General Service Customers (Schedules I and 7).....
Two-part, Tiered Rates
Three-Part. Tiered Rates
Time-Of-Use ..............
B. Residential and Small General Service On-Site Generation Customers (Schedules
6 and 8)............
C. Large General Service-Secondary Service (Schedule 95) ...........
Removal of Demand and BLC Inclining Block Structure and introduction of
Time-of-Use Energy Rates
.l
ii
ii
iv
....5
7
.... 1 I
.... I 3
.... I 3
.... I 3
.......... I 5
..........16
..........16
..........19
..........22
23
25
26
26
28
3l
36
39
40
IPC-E-18-16 Fixed Cost Report Page i
ldaho Power Company
ldaho Power Company Table of Contents
D. Large General and Large Power-Primary Service (Schedule 9P and l9P).....
E. Irrigation Service (Schedule 24)............
.....4t
.....43
.,.,.45Introduction of BLC...
VII. Conclusion.........47
Table I
2017 customer class characteristics 10
Table 2
Scenario No. 1 CCOS model....17
Table 3
Scenario No. 2 CCOS model..
Table 4
Rate Designs Considered ..25
LIST OF FIGURES
Figure I
Revenue collection to cost comparison .2
Figure 2
Bonbright's Ten Ratemaking Principles .....8
Figure 3
My Account, kWh data...........
Figure 4
Illustrative overview of system facilities
9
ll
Figure 5
Class cost of service process
Figure 6
2017 company's CCOS revenue change required by rate schedule ($M)
t2
t4
Figure 7
Rate schedule CCOS revenue percent change required (%). .
Figure 8
Summary of 2017 CCOS results.......
Figure 9
Scenario No. 1 interclass impact-required revenue.....
t4
15
18
Page ii IPC-E-18-16 Fixed Cost Report
LISI OF TABLES
ldaho Power Company Table of Contents
Figure l0
Scenario No. 1 intraclass impact.......
Figure 11
Scenario No. 2 interclass impact-required revenue...
Figure 12
Scenario No. 2 intraclass impact.......
Figure 13
Scenario No. 3-fixed costs accounting definition .....
Figure 14
Collection of revenue: base case
Figure 15
Collection of revenue: three-part, tiered rate
Figure 16
Residential energy use per customer and residential demand per customer..................
Figure 17
Percentage of residential customer average monthly impact-base case to three-part,
tiered rate....
Figure 18
Collection of revenue: time of use, cost based.....
Figure 19
Percentage of residential customer average monthly impact-base case to TOU
Figure 20
Collection of revenue: time of use (5:1) .........
Figure 25
Collection of revenue: TOU
Figure 26
Collection of revenue: base case
.19
.21
.22
.23
.28
.29
.30
.31
JJ
35
Figure 2l
Percentage of residential customer average monthly impact-base case to 5:l TOU ...36
Figure 22
Collection of revenue: on-site generation using current rate structure 37
Figure 23
Collection of revenue: on-site generation net hourly using current rate structure.......38
Figure 24
Collection of revenue: base case .40
34
.4t
42
IPC-E-18-16 Fixed Cost Report Page iii
ldaho Power Company Table of Contents
Figure 27
Collection of revenue: cost of service informed
Figure 28
Collection of revenue: base case
Figure 29
Collection of revenue: BLC
LIST oF APPENDIcES
Appendix A
Scope of Attributes to be Studied (Attachment A-Staff s 4l30ll9 Report, IPC-E-18-
l6)............
Appendix B
Development of 2017 Results of Operations
Appendix C
Class Cost of Service Process Guide
Appendix D
Class Cost of Service Study Results
Appendix E
Scenario No. I Individual Modification Impacts..
Appendix F
Scenario No. 2 Individual Modification Impacts..
Appendix G
Revenue Requirement and Fixed-Variable Proportion Cost of Service Analysis by Class.
.43
44
.45
._..49
5l
...57
...67
.7t
t3
Appendix H
Time of Use Period Selection
Appendix I
Schedules I andT Base Case Compared to Three-Part, Tiered Rates ......................79
Appendix J
Schedules I and 7 Base Case compared to Time of Use (Cost-Based) Rates ..........81
Appendix K
Schedules I andT Base Case compared to Time of Use (5: l) Rates ......83
Appendix L
Schedule 95 Base Case compared to TOU Rates .................85
Appendix M
Schedules 9P Base Case compared to Full COS
7l
Page iv IPC-E-18-16 Fixed Cost Report
ldaho Power Company Table of Contents
Appendix N
Schedules 24 Base Case compared to Basic Load Charge 9l
IPC-E-18-16 Fixed Cost Report Page v
ldaho Power Company Table of Contents
Page vi IPC-E-18-16 Fixed Cost Report
ldaho Power Company Executive Summary
l. Executive Summary
Fixed costs are those costs that do not vary by any measure of use of the system; these costs
constitute a majority of the costs a utility incurs to provide electric service to its customers.
Historically, the simplest and most common way for a utility to collect revenue from residential
customers (both from an availability of metering technology and customer understanding
standpoint) has been through volumetric energy charges coupled with a fixed service charge. In
choosing this rate design, regulators have weighed many issues-the benefits of encouraging
conservation, customer understanding of utilizing volumetric usage as a basis to collect costs,
and the range of revenue uncertainty when fixed costs are recuperated via volumetric charges.
"For this type of rate design, revenue recovery is at risk of any reduction in usage (e.g., due to
variation in weather or demand energy response [DER]) unless there is a mechanism that
decouples revenue from customers' usage."1
The existing rate designs for Residential, Small General, Large General, Industrial, and Irrigation
classes collect a portion of fixed costs through volumetric rates rather than collecting the full
fixed costs (customer and demand related) through the fixed monthly service charge and
demand-related components of the rate design. This is especially true for Residential and Small
General Service customers where fixed costs represent approximately 70 percent of the total cost
to serve, while between 90 and 95 percent of total revenue is collected through volumetric
energy charges. Because the energy rate is the primary component for collection of fixed costs
related to generation, transmission, and distribution, the recovery of fixed costs per customer
declines with any reduction in net energy usage and increases when net energy usage is greater
than expected.
A side-by-side comparison for each customer class for the existing rate design revenue collection
proportions ("Revenue" column) versus the fixed and variable proportions informed by the most
recent cost of service methodology ("Cost" column) is provided in Figure I to indicate how close
or far any class's revenue collection proportions are to the current underlying cost structures.
I NARUC Manual on Distributed Energy Resources Rate Design and Compensation,pp.63-64 (2016)
IPC-E-I8-'tO Fixed Cost Report Page 1
Residential Residential
On-Site
Small
General
Small General
On-Site
Large
General
Large
General P/T
lndustrial lrrigation
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80%
60%
40%
20%
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Figure 1
Revenue collection to cost comparison
As can be seen in Figure 1, existing rate designs result in fixed and variable revenue collection
that does not match fixed and variable proportions of incurred costs. Idaho Power Company's
(Idaho Power or company) cost structure is largely fixed in nature and Figure I demonstrates that
opportunity exists to better align revenue collection with cost structures.
This misalignment of revenue collection with the overall cost-structure is the reason why a
decoupling mechanism, the company's Fixed Cost Adjustment (FCA) mechanism was
implemented. The FCA is an efficient and necessary mechanism that removes the financial
disincentives that would otherwise exist when Idaho Power pursues energy efficiency on behalf
of its customers. Applicable only to Residential and Small General Service classes, the FCA
corrects for the majority of over, or under, collection of fixed costs that results from the use of
volumetric charges to collect the majority of fixed costs for those classes.
Many of the cost of service study methodologies and rate designs presented in this report, if
implemented, would impact the level of reliance on the existing FCA (either up or down) or
warrant consideration of a modified fixed cost recovery mechanism. It is critical to note that
continued reliance on volumetric or otherwise variable rate components, including demand
charges, for the collection of fixed costs would warrant continued consideration of decoupling
mechanisms like the FCA.
Page 2 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Executive Summary
ldaho Power Company Executive Summary
It is also important to recognize that conditions have changed since the current rate designs were
established .In 201l, the company largely completed deployment of advanced metering
infrastructure (AMI) in its service area. AMI enabled the company to achieve more precise usage
measurement and facilitate more sophisticated, cost-based rate designs. The company has also
been successful at encouraging its customers to install energy efficient technologies and to use
energy wisely through its energy efficiency program portfolio and marketing campaigns. In 2018
alone, the company's demand-side management programs saved enough energy to power over
16,000 average homes for one year in Idaho Power's service area.
Additionally, the company has experienced rapid growth of customers choosing to provide some
of their own annual energy needs with on-site generation. Because the volumetric rates contained
within the company's current retail rate structure include costs associated with all components of
the electric system-from generation resources to the meters installed on customers' premises-
volumetric rates do not properly assign the costs and benefits of the transaction between Idaho
Power and its customers with on-site generation. This leads to the potential for increasing intra-
class subsidies.
In its Order No. 34046, the Idaho Public Utilities Commission (Commission) recognized these
issues and directed the company to undertake a study investigating fixed cost recovery in basic
charges and other rate design options prior to its next general rate case. In compliance with that
Order, the company has prepared the following fixed cost study report (Report) that provides an
overview of the rate design process, explains the class cost of service (CCOS) process, discusses
the results of the 2017 CCOS developed as a basis for this Report along with a number of
potentially modified CCOS scenarios, and finally presents an evaluation of a variety of rate
design options. The rate design evaluation presented in this Report includes an assessment of the
extent to which each rate design option may provide for recovery of fixed costs in a manner that
aligns with the underlying cost structure, improves fairness in the assignment of costs to
individual customers and appropriately balances a range of policy objectives.
The 2017 CCOS study and accompanying CCOS scenarios, all suggest the company's current
cost strucfure is 50 percent or more fixed cost related for every customer class. The company
believes that rate design alternatives that move prices closer to the cost to serve, such as those
presented in the following Report, would lead to significant improvements in the recovery of
fixed costs, provide for rate stability, and result in overall fair and equitable cost allocation by
minimizing customer cross-subsidies. While this Report does not recommend the immediate
implementation of any specific modified rate design options, a number of preferred rate design
options are presented for future consideration.
IPC-E-18-16 Fixed Cost Report Page 3
ldaho Power Company Executive Summary
Page 4 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Background
ll. Background
On July 27 , 2017 ,Idaho Power filed an application in Case No. IPC-E- 17 -13 with the
Commission requesting, in part, for the Commission to issue an order authorizing the (1)
establishment of two new classifications of customers applicable to Residential and Small
General Service (R&SGS) customers with on-site generation, and (2) directing the
commencement of a generic docket to establish a compensation structure for customer-owned
DERs that reflects both the benefits and costs that DER interconnection brings to the electrical
system.
In its final order in the matter, the Commission found that separating on-site generation
customers from standard customers will help the Commission and parties analyze the cost
structure of these customers including subsidization, fixed costs, cost to serve, rates, rate design,
and benefits and compensation for exports (Schedules 6 and 8).2 Further, the Commission
ordered the company to undertake a study investigating fixed cost recovery in basic charges and
other rate design options prior to its next general rate case.3
ln compliance with that order, the company filed an application in Case No. IPC-E- I 8- 16 ( I 8- l6
Case) on October 19,2018, to initiate a process that would facilitate stakeholder input on a
customer fixed cost analysis to be completed by Idaho Power.a
Since the initiation of the l8-16 Case,s the company has met with Commission Staff (Staff) and
interested parties in five settlement workshops and received feedback and input on issues to be
addressed in the company's Report. With consideration of the input received from parties, and in
compliance with Order No. 34046, the company has prepared the following Report for the
Commission's review.
2 IPC-E-I7-13, Order No. 34046 at 17
3 Id. at 31
4IPC-E-18-16, Application at 3
s The Notice of Parties to Case No. IPC-E-18-16 lists: the Idaho Conservation League, Avista Corporation, NW
Energy Coalition, IdaHydro, Idaho Irrigation Pumper's Association, Inc, Rocky Mountain Power, Vote Solar, City of
Boise, Idaho Sierra Club, Idaho Clean Energy Association, Industrial Customers of Idaho Power, and Russell
Schiermeier.
IPC-E-18-16 Fixed Cost Report Page 5
ldaho Power Company Background
Page 6 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Rate Design Overview
lll. Rate Design Overview
The basic purpose of rate design is to implement a set of rates for each rate class that produces
the revenues necessary to recover the cost of serving that rate class, otherwise known as the
revenue requirement.6 The revenue requirement is assigned to different customer classes through
the CCOS process, and rates are designed for each customer class to collect that customer
classes' revenue requirement as determined by the Commission. Customer rates vary by class
and have historically been comprised of several basic components, including the following:
a Service charge-Intended to recover the customer-related costs which do not vary with
change in energy consumption. These costs include investment in the service line and
meter, costs related to customer care functions, as well as costs of meter reading and
billing.
a Demand (kw)-Measures the rate at which energy is used at a point in time.
Billing demand is the average kW supplied during a period of maximum use during the
billing period. Recovers a portion of the capacity-related costs associated with the
generation and transmission of electricity.
a Basic load charge (Blc)-Measured by an average of monthly billing demands or
simply a maximum of an annual billing demand. The Basic Charge, billed on the basis of
BLC, is typically implemented to recover a portion of the capacity-related fixed costs of
the distribution facilities, which includes substations, primary lines and transformers.
a Energy charges-Billed on the basis of kWh, is intended to collect the energy-related
generation costs that vary with consumption of energy by customers. The energy charge
has also been utilized to recover the portion of capacity-related and customer related
costs when these costs are not otherwise collected through the service, demand, or BLC
charges. Energy charges can vary by the time of usage or by the total volume of usage
over the billing period.
Each of these components is informed by the CCOS study and is intended to collect the portion
of the revenue requirement attributed to the customer behavior that requires the company to incur
those costs. To create a proper rate design, it is important to distinguish between fixed and
variable costs-barring other considerations, the company endeavors to collect variable costs
(those that can fluctuate with energy consumption) through the volumetric energy charges and
fixed costs (those driven by customer counts or demand) through fixed monthly service charges
and demand-related charges, including BLC charges.
6 NARUC Manual on Distributed Energlt Resources Rate Design and Compensation, p.20 (2016).
IPC-E-18-16 Fixed Cost Report PageT
ldaho Power Company Rate Design Overview
The National Association of Regulatory Utility Commissioners (NARUC) describes the
importance of cost of service studies in the regulatory process, noting: "cost of service studies
are among the basic tools of ratemaking," "the cost principal applies not only to the overall level
of rates, but to the rates set for individual services, classes of customers, and segments of the
utility's business," and cost studies are used by regulators to "determine how costs will be
recovered from customers within each customer class."7
During settlement discussions, parties discussed several of those considerations referenced
above, identified by Staff as "attributes" that should be considered by the company as it
developed its final Report. The full list of attributes, as compiled by Staff during workshop
discussions, is included as Appendix A to the Report.s The company agrees that the attributes
suggested by parties are important to take into consideration when developing and ultimately
implementing new or modified rate designs. Although this Report may not explicitly touch on
each of the discussed attributes or rate designs identified in Staff s table, all the attributes and
rate designs were taken into consideration when completing the analysis for this Report.
To determine what rate design components may be most appropriate for a given customer class,
it is critical to identify what objectives and principles of rate design a given utility is trying to
achieve. Utilities, stakeholders, and policy makers alike often rely on Bonbright's Principles of
Ratemaking as criteria deemed appropriate for establishing rate structures. Many of the attributes
listed in Staffls attributes also stem from these Bonbright Principles, including the impact on
fixed cost recovery, billing impacts to customers, price signaling and behavior changes, as well
as fair, just, and reasonable rates.
1) Efiectiwness in yielding total re\enue requirements under the fair retum standard
2) Rerenue stability and predictability
3) Stability and predictability of the rates themsehes
4) Static eficiency
5) Faimess in allocation of costs
6) Dynamic effciency in promoting innowtion and responding to changing demand-supply pattems
7) Reflect all present and future pri\ate and social cost in the proMsion of electricity
8) Arcidance of undue discrimination in rate relationships
9) Simplicity, certainty, conrenience of payment, economy in collection, understandability, public
acceptability, and feasibility of application
10) Freedom firom controwrsies as to proper interpretation
Figure 2
Bonbright's Ten Ratemaking Principless
1 The 1992 National Association of Regulatory Utility Commissioners (NARUC) Electric Utility Cost Allocation
Manual, page 12.
8 This table was provided to the Commission as Attachment A and B to Staff s April 30, 2019 Report filed in Case
No.IPC-E-18-16.
e Bonbright, James C. Principles of Public Utilitv Rates,bypp.383-384 (1961).
Bonbrighfs Ten Ratemaking Principles
Page 8 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Rate Design Overview
While there may be some agreement amongst parties regarding the objectives and principles of
rate design, these objectives are often weighted or valued differently by individual parties.
Also important to note, is that a single rate design may not meet all rate design principles and
policy objectives as some may inherently contradict one another. Other goals beyond cost
recovery- rate stability, promotion of energy efficiency, or fair allocation of costs among
customers-are also considered by the company, stakeholders, and the Commission when
ultimately recommending or approving rates. The weighting and balancing of goals may
reasonably shift over time as conditions or circumstances within a given utility's service
area evolve.
Conditions have evolved in Idaho Power's service area since the current rate designs were
established, which provides an opportunity to evaluate other rate designs. In 201 1, the company
largely completed deployment of AMI in its service area. AMI enabled the company to achieve
more precise usage measurement and facilitate more sophisticated, cost-based rate designs. In
addition to providing additional billing possibilities, AMI technology also provides customers
with information to better evaluate, manage, and understand how and when they use energy.
For example, Idaho Power's predominate Residential rate design offering of a small fixed service
charge and volumetric energy rates was established before deployment of AMI technology and
before customers were providing some of their own energy use with on-site generation. Figure 3
provides an example of some of the data customers can currently access using My Account.
Figure 3
My Account, kWh data
The company has been successful at encouraging its customers to install energy efficient
technologies and to use energy wisely through its energy efficiency program portfolio and
marketing campaigns. In 2018 alone, the company's demand-side management programs saved
enough energy to power over 16,000 average homes for one year in Idaho Power's service area.
Additionally, while a net metering offering has been available to customers with on-site
generation since 2002, the company has experienced rapid gowth of customers choosing to
provide some or all of their own annual energy needs in recent years. Because the volumetric
IPC-E-18-16 Fixed Cost Report Page 9
Hourlv kWh
t
3,1
3,6
3,'
2,7
:.4
2.r
1,3
1,5
1,2
o,t
o.a
o,3
:I t E l ;a I I
ldaho Power Company Rate Design Overview
rates contained within the company's current retail rate structure include costs associated with all
components of the electric system-from generation resources to the meters installed on
customers' premises-volumetric rates do not accurately represent the costs and benefits of the
transaction between Idaho Power and its customers with on-site generation, leading to the
potential for intra-class subsidies. Idaho Power believes that improved rate design will result in a
reduction of those increasing subsidies.
In this Report, the company describes additional rate structures that would improve its fixed cost
recovery through the reduction of collecting the revenue requirement associated with fixed costs
through volumetric charges, sending clearer signals to customers regarding the cost-to-serve
while still providing customers with an opportunity to modify behaviors to reduce their bill. The
usage and service characteristics of the customer classes studied within this Report are outlined
in Table 1.
Table 1
201 7 customer class characteristics
I I 2017 | 2o17Ar"r"se lzotzlreraselI I Averase I Monthty I Monthty I
custorner I nate lcustonrr I custonpr I oenana lrvg IType I Schedule I Count I Usage(k\tuh) lbyCustonnrI EligibilityTlpe of Service
Residential
Rsid6ntial
Small general
Small gereEl
Large general
Large power
lrigatim
Schedule'1
Schoduls 6
Schedule 7
Schadule I
Schedule 9S
Scheduls gP/T
Schedule'19
Schsdule 24
430,921
1,088
28,136
u
33,955
223
110
1 8,104
955
785
365
7,876
186,885
I,650,799
8,079
I Single phase, '120 or 240 rclts
'10 Single phffie, 120 tr 240 rclts
3 Single or thre+phase, 480 rclts or less
5 Single tr threBphase, 480 wlts or l6s
26 480 wlts or less
476 12.5 kilmlts (kV) to 34.5 kV
3,190 '12.5 kilowlts (kV) to 34.5 kV
4 - in seasm Single or lhBe*hase, 480 \olts q l6s
Domestic use
Dmastic Ge, m€ite gonoration
Commercial use, < 2,000 kwh
Cmmercial use, < 2,000 kwh, m€ite gBmmtim
Commercial use, > 2,000 kwh
Cmmrcial uss, > 2,0@ kwh, <'1,000 kW
lndustrial use, >1,000 kW
Agricullural us6
To evaluate proper rate design, Idaho Power believes it is first appropriate to identify and
understand what customer behaviors drive Idaho Power to incur costs-identified through a
CCOS study-and to understand which rate design elements can achieve important policy
objectives and rate design principles.
Page 10 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Class Cost of Service Process Review
lV. Class Gost of Service Process Overview
A cost of service study is used to assign or allocate a fair share of the utility's total revenue
requirement to the various customer rate classes or schedules; the output of the CCOS is the cost
of service or revenue requirement for each rate class or schedule. The CCOS is developed
through a three-step process that recognizes the way costs are incurred by relating these costs to
the way in which the utility is operated to provide electrical service. The process consists of a
jurisdictionalized test year required revenue that is: (1) categorizedby function
(functionalization), (2) classified based on the utility service being provided (classification), and,
finally, (3) allocated to customer classes (allocation). Figure 4 provides an illustrative example of
the types of facilities that are necessary for each of the distinct types of customers classes.
Gencration
Largc Gencnl CustomGrs
Schedule 9P
lrrigation Cudomcrs
Schedule 24
Scheduls 1 and 6 Sccondary Scryic CustomcE
Schedules 7,8 and 95
Figure 4
lllustrative overview of system facilities
Functionalization is the process of dividing the total revenue requirement into functional
components as related to the operating functions of the utility: production, transmission,
distribution, metering, customer service, etc., and generally follows Federal Energy Regulatory
Commission (FERC) Uniform System of Accountsro prescribed for public utilities.
10 Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject to the Jurisdiction of the
Federal Power Act, codified at 18 C.F.R. Part 101.
lndusEirl CusbmlE
Schedules 19 and 9I
IPC-E-18-16 Fixed Cost Report Page 11
4 tr
Stcp-Up Tnnrformcl
ldaho Power Company Class Cost of Service Process Review
Classification is the process of separating the functionalized costs by the primary driver for that
cos! being either customer-related, demand-related, or energy-related, through direct assignment
or allocation factors to enable cost assignment based on cost causation. In this step of the
process, primary attention is given to whether the cost varies because of changes in (1) the
number of customers, (2) demand imposed by the customers to serve their maximum energy
needs kilowatt (kW), or (3) energy used by the customers kilowatt-hour (kwh).
Once costs have been functionalized and classified, allocation to customer classes is completed
through customer class allocation factors to divide up system and customer class share of the
company's overall revenue requirement. Results of the CCOS study are presented as unit costs,
which provide each customer class's revenue requirement by functionalized and classified
component to inform cost of service based rate design. Figure 5 provides an overview of the
CCOS and rate design process.
Required Revenue
Functionalization
Classification
Allocation
Unit Costs
Figure 5
Class cost of service process
Generation Related
Energy DemandRelated Related
Demand Customer
" f_elated lqEt_"_A
Ir
Demand
Related
:;;
Page 12 IPC-E-18-16 Fixed Cost Report
{Transmission Related Distribution Related
,l
{
{
{
Energy
Charge
I
ldaho Power Company 2017 Class Cost of Service
V. 2017 Class Gost of Service
A. Development of the 2017 CCOS
To develop the 2017 CCOS, the company first prepared a 2017 Results of Operations (ROO)
based on l2-months ending December 31, 2017 , using a methodology similar to developing a
historical test year in a general rate case (GRC). While this process included standard regulatory
adjustments including normalizing and annualizing adjustments, no financial data was grown or
forecasted and the ROO does not include a requested rate of return. The results of the ROO were
input into a jurisdictional separation study (JSS) to determine the Idaho jurisdictional ROO
(Idaho ROO). A detailed explanation of the process used to develop the Idaho ROO is included
in the Report as Appendix B.
After the Idaho ROO was determined, the company used a methodology consistent with that
approved by the Commission in the 2008 GRC and the same method filed by the company in the
2011 GRCIr to complete the 2017 CCOS study. Some modifications were necessary to
incorporate new Schedules 6 and 8, and to develop an allocation methodology for company
generation resources added since the 2011 rate case. Appendix C to the Report is a detailed
overview of the company's CCOS process and describes the existing methodology and necessary
adjustmentsl2 in greater detail.
Because the company is not seeking changes to its authorized revenue requirement on a system
basis, the 2017 CCOS study was completed based on the overall rate of return achieved by the
normalized 2017 actual results (7.20 percent), not at the most recent Commission-authorized
overall rate of return (7.86 percent). The company presents these results to inform the
Commission of potential inter- and intra-class subsidies as they exist at the company's
normalized and annualized2}ll revenue from the current rates.
8.2017 CCOS Results
A required revenue summary of the 2017 CCOS study highlighting results by rate schedule is
provided in Appendix D. This summary includes each rate schedule's allocated rate base, sales
revenue, operating income, and achieved rate of refurn. Further, the summary also provides each
class's earnings and revenue deficiency (or excess) and the revenue percentage change to
achieve the required revenue as defined in the company's CCOS study.
rrThe company's most recent general rate case was Case No. IPC-E-11-08, which was settled without approval of
cost of service methodology. The Commission most-recently approved the company's cost of service methodology in
the previous general rate case, Case No. IPC-E-08-10.
r2 The company believes the adjustments made to incorporate Schedules 6 and 8 result in reasonable allocation of
system costs, but notes that not all parties agreed with the company's method.
IPC-E-18-16 Fixed Cost Report Page '13
ldaho Power Company 2017 Class Cost of Service
Figure 6 provides a comparison by rate schedule of the amount of additional (or reduced)
revenue collection necessary to eliminate the existing revenue surplus/deficiency by class
according to the company's 2017 CCOS.
(s1s.3M)
(s14.sM)
(s1.oM)
So.ozwt
so.sM
s1.7M
s8.6M
Szr.rvt
Figure 6
2017 company's CCOS revenue change required by rate schedule ($M)
To equalize for differences in magnitude of revenue collection from each rate schedule, as
defined by the company's 2017 CCOS, Figure 7 is provided as a second comparison of change
required to meet required revenue for each class based on percentage change to that respective
rate class's revenue collection.
Residential
Large General
Small General
Small General On-Site
Residential On-Site
Large General (P/T)
lndustrial
lrrigation
Residential
Large General
SmallGeneral
SmallGeneral On-Site
Residential On-Site
Large General (P/T)
lndustrial
lrrigation
a 5.6%
- 7.5%
I L5,8%
-4.2% -
-5.s% -
-6.3% -
LOO.0%
45.9%
Figure 7
Rate schedule CCOS revenue percent change required (%)
With the exception of the newly established onsite generation classes, the differences between
classes in revenue change necessary to meet the company's 2017 CCOS in Figures 6 and 7 is
largely a result of final revenue spread considerations from prior rate cases. Changes in CCOS
methodologies between rate cases combined with the cap and spread considerations may
magnify the over- or under-allocation revenue collection for each rate class.
Page 14 IPC-E-18-16 Fixed Cost Report
ldaho Power Company 2017 Class Cost of Service
G. Effectiveness of Existing Rate Designs to Gollect
Fixed Costs
As informed by the company's 2017 CCOS study, each customer class's required revenue by
functionalized and classified component was utilized to evaluate the effectiveness of existing rate
designs to collect fixed costs. First, the 2017 normalized retail revenue for each rate class was
summed to determine the proportion of revenue collection through customer, demand, or energy
charges from the existing rate design. Next, classified costs from the company's 2017 CCOS
study were separated into the same classifications. A side-by-side comparison for each customer
class for the existing rate design revenue collection proportions ("Revenue" column) versus the
fixed and variable proportions informed by the most recent cost of service methodology
("Cost" column) is provided on Figure 8 below to indicate how close or far any class's revenue
collection proportions are to the current CCOS study informed proportions. Of note, this graph
is not designed to show collection shortfalls, rather the percentile comparison between how
revenue is collected and the underlying cost of service informed fixed and variable costs.
Residential Residential
On-Site
Small
General
Small General
On-Site
Large
General P/T
La rge lndustrial lrrigation
General
700%
80%
60%
4Oo/o
20%
o%
ccr .s""q.d
oci'.s"'
$d
<ro*
&co'^Jood"
cct'..oo"^s$"
c,ci'.."".q.d
c,ci'c^{$"
c,ct"
I Energy r Demand Service Charge
Figure 8
Summary of 2017 CCOS results
As demonstrated in Figure 8, the existing rate designs for the company's Residential, Small,
Large General, Industrial, and Irrigation classes do not collect the full fixed costs (customer and
demand related as calculated in the company's 2017 CCOS) through the fixed monthly service
charge and variable demand-related components of the rate design. This is especially true for
IPC-E-'18-16 Fixed Cost Report Page 15
ldaho Power Company 2017 Class Cost of Service
Residential and Small General Service customers; between 90 and 95 percent of total revenue is
collected through volumetric energy charges and yet approximately 70 percent of total costs to
serve are fixed in nature. Because the energy rate is the primary component for collection of
fixed costs related to generation, transmission, and demand-classified and distribution, the
recovery of fixed costs per customer declines with any reduction in net energy usage and
increases when net energy usage is greater than expected. For the Residential and Small General
Service classes, the FCA corrects the misalignment between the revenue collection and the cost
structure by decoupling the collection of fixed cost from the volumetric energy charges and
recoupling to customer counts.
D. Potential Modifications to the CCOS Methodology
In recognition that changes to the CCOS methodology may result in different classifications of a
cost as either fixed or variable, parties asked the company to evaluate the impact of certain
modifications to the company's CCOS study on the classification of fixed costs as well as how
such fixed cost classification may impact the evaluation of the effectiveness of rate designs.
Ultimately, two parties suggested multi-part modifications for the company to consider-each
are described and presented below as CCOS Scenario No. 1 and CCOS Scenario No. 2.
Additionally, one party asked the company to present the results of its 2017 CCOS using a
classification method for generation plant-related fixed costs that more closely aligns with an
accounting definition of fixed cost in lieu of the company's existing Commission-approved
classification of those resources as both variable (energy) and fixed (demand)-this is described
and presented below as CCOS Scenario No. 3.
CCOS Scenario No. 1
Scenario No. I consists of four potential modifications in classification and allocation factors
that affect the spread of interclass and intraclass customer class costs as calculated by the
company's cost of service model.
Page 16 IPC-E-18-16 Fixed Cost Report
ldaho Power Company 2017 Class Cost of Service
Table 2
Scenario No. '1 CCOS model
Category
Existing CCOS
Methodology
Requested
Modification lnterclass lmpact
1. Demand
Response
2. PURPA
Capacity
3. Base-load
Production
Plant
4. Fixed
Transmission
Plant
Classified to demand and energy
based on composite of baseload
and peaking plant demand and
energy classification
Classified to demand and energy
based on composite of
production plant demand and
energy classification
Allocated to classes based on
class's proportion of 12 monthly
coincident peaks
Classified 100% as demand
Classify as 100%
demand
Shifts required revenue allocation
to classes with summer
"peakiness"
Classify as 100%
demand
Shifts required revenue allocation
to classes with summer
"peakiness"
Allocated to
customer classes
based on "above
average load"
Classify as 50%
demand,50%
energy
Shifts required revenue allocation
to classes with summer energy
requirements greater than
remainder of year
Shifts required revenue allocation
to high load factor classes
The request for the first and second modifications were driven by the desire to have capacity-
related costs associated with both demand response and PURPA classified as demand, instead of
energy. These modifications resulted in customer classes with higher summer peaks receiving
higher allocable shares of revenue requirement.
The third modification was requested to replace the existing l2 monthly coincident peak (12CP)
methodology of assigning base-load production plant with an "above average load" methodology
that is intended to evaluate each hour of the test year by rate class and to only allocate base-load
production costs for any hours where consumption exceeded the annual average.
Generally, where the existing method results in every class receiving an allocable share of base-
load production plant based on its load at the time of each monthly system peak, the modification
resulted in base-load production plant allocation being heavily concentrated in the company's
peak summer period, where approximately 85 percent of the "above average" load occurred.
Under this method, no base-load plant was assigned to any hour where the load is less than the
average. Due to its high energy usage during May to September, the customer class most
impacted by the increase to allocation to summer season was the Irrigation class. All other
classes experienced a revenue requirement decrease because of the modification.
The final modification to change the transmission plant classification from 100 percent demand
to 50 percent demand and 50 percent energy generally resulted in higher load factor customers
receiving more cost assignment (Industrial), and lower load factor customers receiving less cost
assignment (Residential).
The modifications in Scenario No. 1 impact both inter- and intra-class subsidies through the
allocation of required revenue among classes (interclass), and the fixed and variable cost
allocation proportions within each class (intraclass). The impact of Scenario No. 1 on interclass
subsidies is demonstrated on Figure 9 which compares the required revenue informed by the
CCOS study and the combined impact of the four modifications for Scenario No. l-under this
IPC-E-18-16 Fixed Cost Report Page 17
ldaho Power Company 2017 Class Cost of Service
scenario, the revenue requirement for all customer classes would decrease, with the exception of
the Irrigation class, who would experience a $43 million, or 29 percent, increase in
revenue requirement. Impacts for each of the four modifications in Scenario No. 1 are
individually compared to required revenue informed by the CCOS study in Appendix E.
Residential Residential
On-Site
Small Small General Large
General On-Site General
La rge lnd ustria I lrrigation
General P/T1,40%
LOO%
80%
60%
40%
20%
0%I Cost Scenario 1
Figure 9
Scenario No. 1 interclass impact-required revenue
Impacts of Scenario No. I to intraclass subsidies is demonstrated in Figure 10. This compares the
fixed- and variable-cost proportions informed by current revenue collection, the 2017 CCOS
study, and the combined impact of the four modifications for Scenario No. l.
120%
P=-c.rh
ofco
oL
Eo.!
JooE,
Page 18 IPC-E-I8-16 Fixed Cost Report
ldaho Power Company 2017 Class Cost of Service
lndustrial lrrigation
LOO%
90%
80%
70%
60%
50%
40%
30%
20%
tOo/o
Oo/o
I Energy r Demand Service Charge
Figure 10
Scenario No. 1 intraclass impact
While the modifications proposed through Scenario No. I ("Scenario 1" column) materially
changed the costs allocation to customer classes / revenue spread, the impact to the development
of the class-specific cost structures (as depicted in Figure 10) was relatively minimal. Therefore,
the assessment of the effectiveness of fixed cost collected through the fixed components of the
existing rate design for all customer classes is only slightly improved under this modification.
CCOS Scenario No. 2
Scenario No. 2 also consists of four potential modifications in classification and allocation
factors that affect the spread of interclass and intraclass customer class costs as calculated by the
company's cost of service model.
Residential Residential
On-Site
Small
General
Small General
On-Site
Large
General
Large
General P/T
*.""t'"ro{."."t*"."ttt$,""-..d"$'c-".""t$t'"t*."".et$"t'"t-"."$"r$".J*."..d"r:1".'"to."..d'r$.c
IPC-E-18-16 Fixed Cost Report Page 19
ldaho Power Company 2017 Class Cost of Service
Table 3
Scenario No. 2 CCOS model
Category
Existing CCOS
Methodology
Requested
Modification lnterclass lmpact
1. Distribution
Plant FERC
Accounts
364-368
2. Market
Purchases;
PURPA
3. Fixed
Transmission
Plant
4. On-Site
Generation
Distribution
Plant
Allocator
Classified to demand and
customer based on 3-year load
duration curve
Customer classes with
smaller customer counts
receive greater distribution
cost assignment
Shifts required revenue
allocation to classes with
summer "peakiness"
Shifts required revenue
allocation to classes with
summer energy requirements
greater than remainder of
yeat
Lowers distribution plant
allocation to on-site
generation classes
Classified to demand and
energy based on composite of
production plant demand and
energy classification
Classified 100% as demand
Annual non-coincident peak
(l NCP) based on delivered or
received demand for class
Market purchases-
100% energy; PURPA
follows energy/capacity
as characterized in
ldaho ROO
Classify as 50%
demand, 50% energy
(or by ldaho
jurisdictional load factor)
Annual non-coincident
peak for delivered (to
customer) demand at
the time of combined
schedule 1 and 6, and 7
and 813
The modification to classify distribution costs related to overhead and underground conduit,
poles, underground conductors and devices, and line transformers (FERC accounts 364-368)
as 100 percent demand matches the existing CCOS methodology for distribution substations,
which are norrnally built to serve a particular load and whose size is not affected by the number
of customer served. However, the number of poles, conductors, and transfoffners are directly
related to the number of customers on the utility's system. Allocation of distribution plant
accounts 364-368 between a demand and customer classification is commonly accepted in the
electric utility industry and conforms with classification methods outlined by NARUC.ta
Distribution plant accounts (364-368) are currently classified as demand-related or customer-
related using a fixed to variable ratio derived from a three-year average load duration curve
which seeks to approximate a system capacity utilization measurement. The system utilization
measurement indicates the portion serving load in 99 percent of hours and classifies that
portion's costs as customer related, while the balance is classified as demand related costs. There
is a minimum amount of load the distribution system must be ready to serve solely due to the act
13 The company did not have a load research sample representative of the combined Rate Schedule 116 and718 and
completed the analysis based on the 1NCP at the time of Rate Schedule I and 7, respectively, however to complete
the analysis, it modeled the impact using the INCP for Schedules 6 and 8 at the hour of the Schedule I and 7
classes. respectively.
ra National Association of Regulatory Utility Commissioners, Electric Utility Cost Allocation Manual January, p.
e0. (1992).
Page 20 IPC-E-18-16 Fixed Cost Report
Classify as 100%
demand
ldaho Power Company 2017 Class Cost of Service
of being a customer connected to the system, and classification of those costs as customer-related
is appropriate.
Like Scenario No. l, the request for the second modification was driven by the desire to have
more capacity-related costs classified as demand, which generally resulted customer classes with
higher sunlmer peaks to receive higher allocable shares of revenue requirement. The third
modification to change transmission plant classification from 100 percent demand to 50 percent
demand and 50 percent energy generally resulted in higher load factor customers receiving more
cost assignment (Industrial), and lower load factor customers receiving less cost assignment
(Residential).
Finally, the fourth modification resulted in Schedules 6 and 8 receiving lower cost assignment
from the combination of two drivers: (1) measuring system utilization for delivered energy only
(which ignores any utilization of the system by these classes for their exports), and (2) using the
time of another customer classes' 1NCP resulted in selecting a dayltime when Schedules 6 and 8
1NCP demand is lower. The second part of the modification departs from the current method for
assignment of distribution related cost for all other classes, which recognizes each customer class
receives an assignment based on their maximum contribution to the distribution system.
Figure 11 compares interclass impact based on the required revenue informed by the CCOS
study, current revenue collection, and the combined impact of the four modifications for
Scenario No. 2-under this scenario, the revenue requirement for the Residential and Small
General Service customer classes would decrease, while the Large General Service, Industrial,
and Irrigation classes would experience 7, 10, and 1 1 percent, increases in revenue
requirement, respectively. Impacts for each of the four modifications in Scenario No. 2 are
individually compared to required revenue informed by the CCOS study in Appendix F.
120%
too%
80%
60%
40%
20%
o%
Large lndustrial lrrigation
General P/T
I Cost Scenario 2
Figure 11
Scenario No. 2 interclass impact-required revenue
Similar to the results from Scenario No. l, while the modifications proposed through Scenario
No. 2 ("Scenario 2" column) materially changed the required revenue customer class allocation,
the impact to the classification of fixed costs (as depicted in Figure l2) was relatively minimal.
Residential Residential
On-Site
Small Small General Large
General On-Site General
P
=ErJl
qJ
fcq)
o
E
OJ.=fooE
IPC-E-18-16 Fixed Cost Report Page 21
ldaho Power Company 2017 Class Cost of Service
The effectiveness of fixed cost collected through the fixed components of the existing rate design
for all customer classes is only slightly improved.
Residential lndustrial lrrigation
100%
9Oo/o
80%
70%
60%
50%
40%
30%
20%
10%
o%
I Energy I Demand Service Charge
Figure 12
Scenario No. 2 intraclass impact
CCOS Scenario No. 3
Lastly, aparty requested the company complete an analysis that focused on a more accounting-
driven definition of fixed costs to determine the effectiveness of the existing rate design on fixed
cost collection. Inherent in the company's use of the Idaho jurisdictional load factor to classify
base-load production plant between energy and demand, some portion of fixed plant is classified
as a variable expense-for example,55.4 percent of fixed base load plant is classified as energy
rather than demand within the CCOS. This method has been supported by the Commission in the
past to recognize that the system load factor approach reasonably depicts the Idaho Power
system.r5
The result of this analysis demonstrated that approximately 50 percent of the cost of service
informed variable costs are due to the classification of base-load production plant to demand and
energy by the application of the Idaho jurisdictional load factor. Figure l3 below highlights the
ts IPC-E-08-10, Order No. 30722 at 35.
Residential
On-Site
Small
General
Small General
On-Site
Large
General
Large
General P/T
..r"o'r$..**."""s"r$.'*
.o*1,
-."r?C*."."tt"r$r'**."."tt"r$'c*."."d"r$.'J_"".d"r$.c*..."tt".$-8
Page 22 IPC-E-18-16 Fixed Cost Report
ldaho Power Company 2017 Class Cost of Service
portion of energy classified costs based on the existing CCOS methodology which might be
considered'ofixed" under a strictly accounting definition. When compared to the base case CCOS
method, adoption of this CCOS method and its resulting classification of fixed and variable
costs, would suggest an even greater need to move fixed cost recovery out of volumetric energy
charges into fixed or demand-related charges to better align prices with cost.
Residential lndustrial lrrigationResidential
On-Site
Small
General
Small General
On-Site
Large
General
Large
General P/T
LOO%
90%
80%
70%
60%
so%
40%
30%
20%
LO%
0%
-"""$"r$"J -"."d"r$'.J -"."*"r$"J -"""e"r$"J o."."tt""$'f *."."d"r$t'J -"."d"r$"J o."."tt'"o{."t'J
r Energy !Energy - "Fixed" I Demand o Service Charge
Figure 13
Scenario No. 3-fixed costs accounting definition
The combined impact to both required revenue and fixed and variable proportions for all
suggested modifications is provided in Appendix G by rate class and reflects the information
presented in Figures 8 through 13.
E. CCOS Conclusion
As can be seen in the three scenarios informed by the company's CCOS study, existing rate
designs result in fixed and variable revenue collection that does not match the classification of
the fixed and variable proportions of the company's incurred costs. All three scenarios suggest
the company's cost structure is largely fixed in nature; rates should better align revenue
collection with cost structures. To evaluate different rate design options on fixed cost recovery,
the remainder of this Report is informed based on existing, most recent Commission-approved
CCOS methodology. This includes an assumption that the "base" for rate design comparison is
IPC-E-18-16 Fixed Cost Report Page 23
ldaho Power Company 2017 Class Cost of Service
the existing rate design updated to collect the required revenue for each rate schedules as
informed by the 2017 CCOS study.
Page 24 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Rate Design Analysis
Vl. Rate Design Analysis
The company considered several potential rate designs and ultimately investigated different
class-specific rate design changes to improve fixed cost collection through fixed components of
rate design with an eye towards reducing cross-subsidies. Table 4 provides an overview of those
rate designs considered by the company.
Table 4
Rate Designs Considered
Structure Description lncluded in Report?
1. Single Rate
Component
2. Seasonal
Rates
3. Time of Use
(Energy)
4. Demand
Charges
5. Critical Peak
Pricing (CPP)
or Peak
Rebates
6. Real Time
Pricing
Collects each customer's required
revenue through a single rate element:a. Fixed monthly chargeb. Demand chargec. Energy charged. Connected load charge
Collects a higher proportion of revenue
requirement in the months that are higher
cost to serve.
Collects portions of the revenue
requirement through energy charges that
vary based on established time-periods.
Collects the demand-related portions of
the revenue requirement through demand-
type charges (e.9., billing demand, on-
peak billing demand, or BLC).
CPP: Essentially a TOU rate on most days
of the year, but when the utility system
encounters critical conditions, the peak-
period price rises to much higher, but
known levels, typically on a day-ahead or
day-of basis.
Peak Rebates: Reward customers who
reduce electricity consumption during
periods of high-cost electricity with
monetary rebates.
A rate design that provides customers with
information about the actual cost of
electricity at a given time.
No. Relying on a single rate element for the collection of the
class revenue requirement may improve revenue stability and
fixed cost recovery (in the case of a fixed monthly charge or
connected load charge) but does little to promote efficient
utilization of the system (whether through reducing system
peaks or overall energy efficiency) and is not supported by the
cost of service study.
Yes. ln each of the rate designs studied, an emphasis was
placed on aligning rates with the CCOS study - this generally
resulted in collecting additional costs in the summer months
because serving customer demand is more costly in the
summer-months than the non-summer months.
Yes. TOU energy charges can be effective at sending a price
signal to customers that their energy usage in an on-peak
period may be more costly to serve, however it is important to
recognize collecting fixed costs through a volumetric charge
may impact the company's ability to ensure fixed cost
recovery.
Yes. Demand charges (both TOU and seasonal/monthly) were
evaluated for all customer classes. Demand charges can send
a price signal to customers that encourages a more efficient
utilization of system capacity, however it is important to
recognize collecting fixed costs through a volumetric charge
may impact the company's ability to ensure fixed cost
recovery.
No. ldaho Power has previous experience with running a CPP
pilot in 2005-2006; however in its 2017 lRP, no deficiency
period is identified until 2026. ldaho Power also has the
opportunity to leverage its existing demand response
programs to manage peak if necessary.
No. lmplementation of this type of rate design would likely
require additional metering infrastructure and information
systems, as well as enhancements or upgrades to the billing
system.
IPC-E-18-16 Fixed Cost Report Page25
ldaho Power Company Rate Design Analysis
A. Residential and Smal! General Service Customers
(Schedules 1 and 7)
Customers currently taking service under Schedule 1 (Residential Service) and Schedule 7
(Small General Service) pay a fixed monthly service charge of $5 and a monthly seasonal energy
charge with tiered energy rates. This is typically known as a two-part pricing schedule as it
includes these two main billing components. Under the variable or energy related prices, the
Residential rate structure has three pricing tiersr6 and the Small General Service rate structure has
two pricing tiers.rT The summer energy charges are higher than the non-summer energy charges,
which is intended to reflect the higher cost to serve during the summer months. Residential and
Small General Service customers do not currently have demand or basic load charges. The
application of the current rate structure for Residential and Small General Service customers
results in between 90 and 95 percent of total revenue collection coming through volumetric
energy charges with fixed costs representing approximately 70 percent of total costs to serve.
Because the energy rate is the primary component for collection of fixed costs related to
generation, transmission, and distribution, the recovery of fixed costs per customer declines with
any reduction in net energy usage and increases when net energy usage is greater than expected.
With this relationship in mind, the company believes that these two classes should receive the
highest priority when considering rate design modifications.
Two-part, Tiered Rafes
A primary goal of a tiered structure is to encourage conservation by charging a higher rate as the
energy consumption increases over a billing month. Once a threshold of energy consumption is
exceeded within a billing month, the rate becomes higher to send a price signal intended to
encourage energy efficiency and/or conservation. The tiered rate structure can also be effective
in providing stability in the rates themselves and are considered to be simple for customers to
understand. This existing approach to pricing is a well-tested approach for utility metering
and billing.
On the other hand, the tiered rate structure has potential to unfavorably impact bills of customers
who reside in older, less efficient homes, or those homes with all-electric heat. These customers
may be unable to reduce their energy beyond a certain threshold or may not be able to efficiently
reduce their energy usage in response to the established price signals. Moreover, the tiered rate
structure does not reflect how costs are incurred throughout the billing month and year and does
not send changing price signals at specific or peak hours of the day. A two-part pricing schedule
that collects a portion of the customer-related and all demand-related costs through a tiered
16 In 2009, the Commission approved Staff s recommendation of three-tiered rate structure for Residential customers
finding that the tiered rate structure "is an effective tool to (l) promote energy efficiency within Idaho Power's
increasingly capacity constrained system; and (2) enable cost savings." Order No. 30722 at 40.
t1 [n2004, the Commission approved Staff s recommendation to introduce seasonal two-tiered rate structure for Small
General Service customers, stating it would send a signal to customers to reduce consumption during the summer
months. Order No. 29505 at 56.
Page 26 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Rate Design Analysis
volumetric rate leaves the electric utility potentially unable to collect its authorized level of
fixed costs.
The misalignment of revenue collection with the overall cost-structure is the reason why a
decoupling mechanism like the company's FCA mechanism was implemented. Applicable only
to the Residential and Small General Service classes, the FCA corrects for the majority of over,
or under, collection of fixed costs that results from the use of volumetric charges to collect the
majority of fixed costs for those classes. The rate designs presented in this report, if
implemented, would impact the level of reliance on the existing FCA (either up or down) or may
warrant consideration of a modified fixed cost recovery mechanism.
For example, collecting all customer and demand-related costs through a fixed monthly fee of
approximately $56 (for Residential) and $31 (for Small General Service) customers,
respectively, is likely to increase the company's ability to collect fixed costs through base rates
instead of the FCA; however, it does little to promote other policy objectives (e.9., energy
efficiency or load shifting). Additionally, a hxed flat rate design continues to produce intra-class
subsidies as each customer places different demand on the system at various times throughout
the day and year. Idaho Power believes rates designs that incorporate cost-based service charges
and BLC or demand charges to collect a portion of the demand-related costs better reflect the
individual usage of customers and provide a price signals that customers can respond to.
For purposes of evaluating potential modifications to rate design, the company developed a
"base" rate design for the Residential Schedule I and a "base" rate design for the Small General
Service Schedule 7 as informed by the 2017 CCOS study that mirrors the existing rate design for
those classes, i.e., $5 service charge and tiered energy rates for each customer class.
As demonstrated in Figure 14, under this type of a rate design when customers reduce usage-
whether it is a result of energy efficiency, energy conservation, on-site generation, or a variety of
other factors-the rate design is ineffective at ensuring collection of fixed costs. Likewise, if
usage goes up, fixed costs could be over-collected.
IPC-E-18-16 Fixed Cost Report Page 27
ldaho Power Company Rate Design Analysis
Collection of Revenue
700%
90o/o
80o/o
70%
60%
50%
40%
30%
20%
10%
0o/o
Cost of Base Case
Service
Schedule 1
Cost of Base Case
Service
Schedule 7
I Energy I Demand Service Charge
Figure 14
Collection of revenue: base case
T h ree- P a rt, T i ered Rafes
To understand the merits of a rate design that better reflects how costs are incurred, the company
evaluated a rate design that moves towards a cost of service informed rate design by introducing
demand-related components: an on-peak demand charge that would be assessed between
3-10 p.m.l8 during the summer months and a BLC that would be assessed monthly. As such,
the company's approach to this design is known as a three-partrate design. The three-partrute
design the company studied seeks to collect (1) all customer-related costs through a fixed
monthly service charge, (2) summer production-related costs through an on-peak demand charge
and distribution-related costs through a BLC charge, and (3) all energy-related, the remaining
non-summer production-related, and all transmission-related costs through tiered variable
energy charges.
A demand charge sends an efficiency signal-one that correlates with load factor and encourages
customers to reduce their peak energy usage. While the company's Large Commercial,
Industrial, and Irrigation customers are assessed demand charges based on a l5-minute
18 The summer on-peak demand of 3-10 p.m. is based on an analysis completed using2014-2018 data. The data
indicates 90 percent ofthe daily peak occurs between these hours. Support ofthe development ofon-peak periods
utilized for the Residential and Small General Service rate designs is included in Appendix H.
Page 28 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Rate Design Analysis
measurement, for Residential customers, the company studied a 60-minute measurement for the
assessment of both the summer on-peak demand and the BLC.
The rationale for studying a 60-minute measurement largely centered around customer
understandability and evaluating the customer's ability to respond to the price signal-
Residential and Small General Service customers have access to hourly data on My Account,
providing them with access to see their daily and monthly usage patterns. The introduction of an
on-peak demand charge, in lieu of the traditional monthly billing demand charge assessed on
Commercial, Industrial, and Irrigation customers, is also intended to be easier for customers to
understand because Idaho Power is required to procure or build generation to meet its annual
peak demand, which occurs in the summer months.
A three-part rate design that includes a demand component results in assignment of costs to
customers more aligned with the demand placed on the system by each customer within the
class. As demonstrated by Figure 15, as customer and demand-related costs are moved out of the
energy charge, the revenue requirement is less exposed to eroded fixed cost recovery when
customers reduce overall energy consumption or excess fixed cost recovery when customers
increase overall energy consumption.
Collection of Revenue
100%
90%
80%
70%
50%
50%
40%
30%
20%
t0%
0%
Cost of Three-Part,
Service Tiered Rate
Schedule 1
Cost of Three-Part,
Service Tiered Rate
Schedule 7
r Energy r Demand Service Charge
Figure 15
Collection of revenue: three-part, tiered rate
Figure 16 provides an illustration of how Residential energy and demand per customer, both
variable measurements, are changing over time. While both annual energy and average demand
per customer are declining, monthly energy per customer has declined at arate of approximately
I .3 percent between 2008 and 2018. Demand per customer is declining at a slower rate of
approximately I percent, measured from2014 to 2018. This analysis suggests revenue stability
IPC-E-18-16 Fixed Cost Report Page 29
ldaho Power Company Rate Design Analysis
may be improved by transitioning away from the reliance on total energy usage as the primary
mechanism to collect fixed costs to having some reliance on demand because demand per
customer tends to be more stable than energy use.le It is important to note that the continued
reliance on volumetric or otherwise variable rate components, including demand charges, for the
collection of fixed costs, would warrant continued consideration of decoupling mechanisms like
the FCA to ensure collection of f,rxed costs.
Avg 12
Month
Ending
E nergy
14,000
Residential Demand Per Customer
6.8
13,000
12,000
6.3
11,000
-[6tu3l -felling
12 Month Avg Demand
N
Figure 16
Residential energy use per customer and residential demand per customer
Figure 17 illustrates how customers' bills would be impacted on a monthly basis when rates are
changed from the base case to the three-part, tiered rate. Generally, customers with high energy
use and higher load factors are likely to see decreases in their bills, while customers with low
energy use are likely to see an increase in their bill.
To evaluate the impact of transitioning to this rate design for low income customers, the
company first identified customers who had received paynents from the federal Low-Income
Home Energy Assistance Program (LIHEAP) as a proxy for a segment of low income
customers.20 As a second proxy for low-income customers, the company also studied the bill
re Between 2014-2018, actual residential energy use per customer and demand use per customer have a coefficient
ofvariation of3.3 percent and 1.6 percent, respectively.
20 LIHEAP is a federal program that helps low income households (those that earn 150 percent or less of the annual
federal poverty level) pay for heating their homes. Idaho Power does not administer the LIHEAP program, but it
does notate accounts that have received a LIHEAP benefit in a given year. Because annual LIHEAP funding varies
from year-to-year and a customer who may otherwise qualify may not receive a benefit each year, the company
Page 30 IPC-E-18-16 Fixed Cost Report
Residential Energy Use Per
Customer
Avg
Monthly
Hourly
Demand
0,1.5.8000
@OiOHNm+tn(oF\OOOIooidddidddddooooooooooooNNNNNNNNNNNN
o
oN
e
oN
N
ON
@
ooN
ldaho Power Company Rate Design Analysis
impact to customers who have participated in the Weatherization Assistance for Qualified
Customers (WAQC) or Weatherization Solutions for Eligible Customers (Solutions) programs,
collectively referred to as Weatherrzation.2t Figure 17 shows a three-part, tiered rate structure
may be more favorable to customers that have received LIHEAP or Weatherization assistance;
55 percent and 59 percent of customers having decreases in monthly bills, respectively,
compared to 38 percent of total residential customers who may experience a decrease under this
rate strucfure.
40%
E 35%
o,E 30%(E
? 250/oE
g ZON
OJE 75%oR t0%lus%
0%II
<- sroo -s25 to - -s2s to -sro -sro to so s0 to s10 s10 to s25 s25 to s100 > 5100
Sroo
r All Customers LIHEAP r Weatherization
Figure 17
Percentage of residential customer average monthly impact-base case to three-part, tiered rate
The company has provided additional bill impact analysis within Appendix I demonstrating a
shift from the existing rate design to a three-part rate design will have varying impacts on
customers within the class.
Time-Of-Use
Idaho Power also studied two distinct time-of-use (TOU) rate designs that vary prices by
different periods of the day. TOU rate structures can be effective in sending a price signal to
customers to incent them to shift energy usage to specific hours in the day that are less costly to
serve. Because a TOU rate design introduces a deviation from existing tiered pricing designs,
identified service points that had received a LIHEAP benefit in any of 20 I 6, 2017 , and/or 20 1 8 calendar years for
purposes of studying the impact on this customer segment.
2' The WAqC and Solutions programs help fund weatherization costs of electrically heated homes occupied by
qualified customers who have limited incomes (for WAQC eligible customers earn 200 percent or less of the annual
federal poverty level and for Solutions eligible customers earn between 175 to 250 percent ofthe annual federal
poverty level). This data set included those service points who had participated in the WAQC or Solutions program
in any of 20 1 6, 2017 , or 20 I 8 calendar years.
IPC-E-18-'16 Fixed Cost Report Page 31
ldaho Power Company Rate Design Analysis
additional customer education would be required to assist customers to understand these new
pricing approaches.
The first TOU rate design studied seeks to collect (1) all customer-related costs through a fixed
monthly service charge, (2) distribution-related costs through a BLC charge, and (3) all energy-
related, production-related, and transmission-related costs through time-differentiated energy
charges. The TOU differentials were established by utilizing Idaho Power's actual net power
supply expense data to first determine the price differentials in the energy-related costs. Those
differentials informed the amount of energy-related costs to be collected in each time bucket-
the remaining fixed costs were collected uniformly through the kWh charge.
This TOU rate structure reflects a higher energy rate during periods when energy prices are
higher, both seasonally and hourly. One aspect of this TOU rate design is that it is cost-based; it
reflects the higher energy cost to serve during the summer months and seeks to collect all
customer-related costs through the monthly service charge and distribution-related costs are
collected through a BLC charge, which is demand based. Another aspect of this rate design is
that it may result in reduced power supply costs for the utility by supplying energy to customers
during less expensive times if customers shift their energy requirements to lower cost time
periods. The on-peak energy periods used for rate development are 3-10 p.m. on weekdays
during the summer and 7-11 a.m. and 5-9 p.m. on weekdays during the non-summer months.
Further discussion of the development of the TOU periods is included within Appendix H.
Page 32 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Rate Design Analysis
Collection of Revenue
LOl%
90%
80%
70%
60%
50%
40o/o
30%
20%
70%
0%
Cost of TOU (Cost
Service Based)
Schedule 1
Cost of TOU (Cost
Service Based)
Schedule 7
I Energy : Demand Service Charge
Figure 18
Collection of revenue: time of use, cost based
Figure 19 provides an illustration of the percentage of customers impacted by the change in rate
design from the base case to a TOU rate design. Based on current customer energy use, 67
percent and 63 percent of Residential and Small General customers, respectively, will have an
increase in their monthly bill. If this plan was introduced on a mandatory basis, some customers
may not be able to reduce their energy during certain periods, either seasonally or hourly, and
could result in larger bills for a certain customer segments as compared to a volume-only based
measurement. By collecting all customer-related costs and distribution-related costs through the
fixed service charge and the BLC charge, respectively, this rate design provides an opportunity
for the utility to collect more of its fixed costs directly; however, because the price differentials
between the time periods are low, it may not achieve the behavioral shifts that higher
differentials would.
Moving from base rates to the cost based TOU rate results in 52 percent of LIHEAP and
Weatherization customers having reductions in their bill. The TOU rate design and the resulting
billing impact analysis is presented in Appendix J.
IPC-E-18-16 Fixed Cost Report Page 33
ldaho Power Company Rate Design Analysis
40%
T 35%
E zov"(D* 2s%trg ZON
0.)E 75%o6 t0%f(J s%
0%II
<- Sloo -s2S to - -sZS to -s10 -s10 to $0 s0 to s10 s10 to s25 s25 to s100 > s100
Sroo
I All Customers LIHEAP I Weatherization
Figure 19
Percentage of residentialcustomer average monthly impact-base case to TOU
The second TOU rate design was studied at the request of some parties in the case. Parties
requested that the company study a TOU plan with a 5:1 peak/off-peak price (POPP) ratio with
reference to a study22 that suggested the "peak/off-peak price ratio is one of the strongest
predictors of customer peak load reduction, as higher ratios send a stronger price signal to shift
consumption away from peak hours."23 The company prepared a 5: I TOU design that uses an
on-peak summer weekday period of 3-10 p.m.; all other hours are considered off-peak and are
charged at an off-peak time period.
This type of TOU plan is more like the traditional TOU program used by utilities as a demand-
side management tool intended to shift usage away from capacity-sensitive times. While this
type of a rate structure is expected to result in the shifted usage, because the rate structure does
not reflect the cost to serve (a POPP ratio of 5:l is artificially inflated as energy cost differentials
are much lower), this design likely will not adequately collect the class's fixed costs when
customers shift usage from on-peak to off-peak.2a Furtherrnore, if the TOU program is offered as
an optional TOU offering, it may not be effective in getting customers to shift usage; natural
winners are instead able to take advantage of reduced energy bills with no behavioral change and
no cost savings.
While this type of a rate design is expected to promote behavioral changes, it has similar risks as
the current rate design, where reductions in volume result in the under-recovery of fixed costs
that are included in those on-peak rates. As a result, TOU rate designs may be effective in
22 A Review of Alternative Rate Designs, Aman Chitkara, Dan Cross-Call, Becky Xilu Li, James Sherwood (Rocky
Mountain Institute, 2016). p.27.
23 "A Review of Alternative Rate Designs," p. 6.
2a According to the referenced study, introducing the 5: I differential is expected to result in customers shifting
approximately l0 percent ofusage from on-peak to oflpeak.
Page 34 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Rate Design Analysis
encouraging behavioral changes that may help reduce future costs. However, TOU designs that
are not cost-based may reduce the assignment, and recovery of existing fixed costs, resulting in a
continued need for a mechanism like the FCA.
Collection of Revenue
L00%
90%
80%
70%
60%
s0%
40%
30%
20%
70%
0%
Cost of TOU (5:1)
Service
cost of ToU (5:1)
Service
Schedule 7Schedule 1
I Energy I Demand Service Charge
Figure 20
Collection of revenue: time of use (5:1)
Figure 2 I provides an illustration of the percentage of customers impacted by the change in rate
design from the base case to a 5:1 TOU rate design. Based on current customer energy use,
69 percent of Residential will have an increase in their monthly bill. If this plan was introduced
on a mandatory basis, some customers may not be able to reduce their energy during the on-peak
summer time frame and could result in larger bills for a certain customer segments as compared
to a volume-only based measurement. However, as customers understand how their bills are
affected by their usage, customers are likely to shift their energy usage which may result in a
lower bill than the static presentation below.
Moving from base rates to a 5:1 TOU rate, results in 6l percent of LIHEAP and 53 percent of
Weatherization customers having reductions in their bill, prior to any behavioral changes.
The resulting bill impact analysis is presented in Appendix K.
IPC-E-18-16 Fixed Cost Report Page 35
ldaho Power Company Rate Design Analysis
50%
40%
30%
20%
L0%
Oo/o
<- s100 -s2s to - -s25 to -s10 -s10 to s0 so to sro s10 to s25 s25 to s100 > s100
Sloo
I All Customers LIHEAP I Weatherization
Figure 21
Percentage of residential customer average monthly impact-base case to 5:1 TOU
Of the three rate designs evaluated in this section, the company believes the three-partrute
design that includes a demand component would result in the most equitable assignment of costs
to customers depending on the demand placed on the system by each customer within the class.
As customer and demand-related costs are moved out of the energy charge, collection of the
revenue requirement is less exposed to eroded fixed cost recovery when customers reduce
overall energy consumption. While the rate designs presented in Figure 15 do not perfectly align
with the underlying cost structures for each class, a three-part design would represent a vast
improvement in aligning fixed cost collection with cost causation than the current rate design.
B. Residential and Small Genera! Service On-Site Generation
Customers (Schedules 6 and 8)
Like standard service Residential and Small General Service customers, customers currently
taking service under Schedule 6 (Residential On-Site Generation Service) and Schedule 8 (Small
General Service On-Site Generation) pay a fixed monthly service charge of $5 and a monthly
seasonal energy charge with tiered energy rates; the current rates under each ofthese service
schedules mirror those of the standard service offerings, Schedule I and Schedule 7.
The difference between Residential customers taking service under Schedule 6 (or Small General
Service customers taking service under Schedule 8) and those taking service on Schedules I and
7 is that customers on Schedules 6 and 8 produce some or all of their monthly or annual energy
requirements, but rely on Idaho Power to balance those energy needs when their systems are not
generating. The on-site generation systems installed by customers are designed to generate
electricity when resources (e.g., rooftop solar) are available-without regard to when the
customer actually consumes electricity. To-date, customers with on-site generation have been
billed under a billing construct commonly referred to as net metering where Idaho Power
measures and bills the customer based on each customer's net monthly consumption.
!o)
0(o
o_
E
OJ
Eo
lU II I
Page 36 IPC-E-18-'16 Fixed Cost Report
ldaho Power Company Rate Design Analysis
From a pricing perspective, existing base rates were designed to reflect the bundled set of one-
way power services that the utility provided to the customer-from generation, to transmission,
to distribution. Generally, these base rates have been developed to recover the (1) price of the
power the customer consumes, and (2) payment for the infrastructure needed to deliver that
power to customers reliability.
It is the combination of the billing and compensation structure (currently net monthly billing)
and the existing rate design that creates the potential for an under-recovery of fixed costs from
the on-site generation customers. The solution to the collection of revenue shortfall caused by the
existing net metering policy is multifaceted: (l) the measurement interval of consumption and
exports must be shortened to increase the accuracy and separate the measurement of the usage of
the grid services and the amount of exported energy, (2) the net metering customer's exported
energy should be compensated at a rate that reflects the value of exported energy, but reflective
of the utility's avoided costs, and (3) the rate design for the on-site generation customers should
be unbundled to separate the cost of the power from the cost of the other fixed and reliability
related service (e.g., customer service, distribution, and transmission costs).
The billing and compensation structure, and the value of the exported energy provided by on-site
generation customers, are being evaluated by parties in Case No. IPC-E-18-15; however, for
purposes of this Report, the company evaluated the effectiveness of the current rates
(those applied to Schedules I and 7) under the current billing and compensation structure
(net monthly metering) to determine whether the company would collect the Schedules 6 and 8
revenue requirement as identified by the 2017 CCOS. As shown in Figure 22, under monthly net
metering coupled with the current rate designs, the Schedules 6 and 8 collections are not
adequate to collect each class's revenue requirement.
Collection of Revenue
Schedule 6 Schedule 8
100%
90%
80%
70%
60%
50%
40%
30%
20%
70%
0%
Cost of Base Case Cost of Base Case
Service Service
r Energy I Demand Service Charge \ Revenue Deficit
Figure 22
Collection of revenue: on-site generation using current rate structure
IPC-E-18-16 Fixed Cost Report Page 37
ldaho Power Company Rate Design Analysis
To illustrate the improvement in revenue collection that results from a shorter measurement
interval for consumption2s, the company also evaluated the effectiveness of the current rates
under a "net hourly" billing structure. Under the net hourly billing structure, the measurement
interval of consumption and exports is shortened from measuring net consumption or exports
over the course of a billing month to measuring net consumption or exports that occur on a net
hourly basis. Under this type of a billing structure, the customer's generation will offset up to
100 percent of the customer's usage within each hour, but any excess hourly production cannot
be used to offset kWh consumption in another hour. As shown in Figure 23, while net hourly
billing may reduce the revenue requirement deficiency by approximately 73 and 54 percent for
Residential and Small General Service, On-Site Generation customers, respectively; opportunity
exists to better align the pricing structure with the underlying cost structure.
Collection of Revenue - Net Hourly Billing
Schedule 6 Schedule 8
100%
80o/o
600/o
40%
20%
Oo/o
Cost of Net Hourly
Service
s Revenue Deficit
I Demand
I Energy (Net Metering)
Cost of Net Hourly
Service
Service Charge
IAdditional Net Hourly Revenue
Figure 23
Collection of revenue: on-site generation net hourly using current rate structure
When evaluating potential changes to the rate design applied to the on-site generation customer's
usage, it is important to recognize the proportion of the revenue requirement that is associated
with the price of the power and that proportion associated with the fixed costs of the utility
system. According to Idaho Power's 2017 CCOS study, the proportion of those costs for a
Schedule 6 customer is approximately 32 percent for the energy-classified costs and 68 percent
for the fixed costs, and for Schedule 8 customers approximately 23 percent and77 percent,
2s CCOS is completed with cost assignment on a net hourly basis, therefore, using an hourly interval for rate design
provides a more consistent comparison.
Page 38 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Rate Design Analysis
respectively. Continuing to apply the Schedule I and J rate designs (where the majority of fixed
costs have been collected through a volumetric rate) to customers who are able to offset their
consumption may not provide an opportunity to recover the classes' fixed costs absent a
mechanism like the FCA. As outlined in the Schedules 1 and 7 rate design discussion, relying on
a service charge to collect customer-related costs, a demand-based charge such as a BLC to
collect those costs associated with the distribution system, and a billing demand or on-peak
billing demand to collect costs associated with utility generation and transmission, would result
in better alignment of revenue collection with the assignment of costs.
C. Large General Service-Secondary Service (Schedule 95)
The current rate structure for Large General - Secondary Service includes a monthly service
charge, a two-tier declining block energy charge, a two-block demand and BLC. The demand
charge and BLC have a block-rate that applies to the first 20 kW of billing demand or BLC (the
rate is currently $0 for the first 20 kW of billing demand or BLC) and the second block applies to
all additional kW. The first tier of energy is higher priced than the second tier because the
demand-related costs that would have been collected through the first block of the billing
demand and BLC are instead collected through the first tier of the energy charge.
The existing rate design is generally understandable to Large General Secondary Service
customers and administration is well tested for the company. The current rate design was
instituted to minimize the impact to Small General Service customers transitioning onto the
Large General Service Schedule.26 However, the current block schedule for energy, demand and
the BLC does not send a price signal to encourage consumption at any specific time as compared
to a time of use rate design. Moreover, the absence of a price for the hrst 20 kW of demand and
BLC signals to customers that there are no fixed costs associated with serving this demand.
Generally, having a tiered structure shields customers that are low energy users with minimal
energy consumed during the customer's highest 15-minute interval.
For purposes of evaluating potential modifications to rate design, the company developed a
"base" rate design for Large General Service Secondary, Schedule 95, as informed by the 2017
CCOS study by utilizing the existing $16 service charge, $0 first-block of demand, and tiers for
the energy. As demonstrated in Figure 24,under this type of a rate design the majority of hxed
costs continue to be collected through the volumetric charge. That is, over 80 percent of total
revenue collection for this class is through a volumetric energy charge when over 50 percent of
the costs to serve this class are fixed in nature.
26 IPC-E-05-28, Pengilly Direct, p. l7
IPC-E-18-16 Fixed Cost Report Page 39
ldaho Power Company Rate Design Analysis
Collection of Revenue
700%
90%
80%
70%
60%
s0%
40%
30%
20%
70%
0%
Cost of Service
r Energy I Demand
Base Case
Service Charge
Figure 24
Collection of revenue: base case
Removal of Demand and BLC lnclining Block Structure and
introduction of Time-of-Use Energy Rates
As an alternative to the current or base rate design, the company evaluated a cost-based rate
design that seeks to collect all customer-related costs through the monthly service charge,
all transmission and fixed production-related costs through a demand charge, all distribution
costs through the BLC, and all energy-related costs through a time-differentiated energy charge.
Because Large General Service Secondary customers currently have demand and BLC rate
components, the changes would require minimal education to customers regarding demand.
The incorporation of an on-peak, mid-peak and off-peak summer rates, and mid-peak and off-
peak non-summer rates would provide an economic signal that energy is costlier during both the
peak hours of the day and peak months of the year.27 A change in rate design would require
customers to receive education on the new energy rates and how shifting their energy use will
affect their bill. This rate design results in a much lower energy rate during the off-peak times
and higher energy rates during the on-peak summer time. Additionally, this rate design would
27 For purposes of evaluating this rate design, the company utilized the existing TOU periods for Large General
Primary and Large Power customers. The on-peak energy time frame is in the summer, on weekdays from l-9 p.m.
and mid-peak during the summer weekdays during 7 a.m.-l p.m. and 9-l I p.m., and 7 a.m.-l I p.m. on weekends.
Mid-peak during the non-summer months is 7 a.m.-1 I p.m. Monday*Saturday. All other hours and holidays are
considered off-peak.
Page 40 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Rate Design Analysis
not require upgrades to metering infrastructures and billing systems as the existing systems could
accommodate this type of rate design.
Under this rate design, higher load factor customers and those that can shift their usage outside
of higher priced periods will likely see a decrease in their bill; lower load factor customers or
those that cannot shift their usage outside of higher priced periods will see an increase in their
bill. Additionally, low energy users with low demand will see a decrease in their bill.
As demonstrated by Figure 25, as customer and demand-related costs are moved out of the
energy charge, the collection of the revenue requirement is tied to the underlying cost structure
and the company is less exposed to under collecting fixed costs when customers reduce overall
energy consumption.
Collection of Revenue
100%
90%
80%
70o/o
60%
s0%
40%
30o/o
20o/o
L0%
Oo/o
Cost of Service
I Energy I Demand
TOU
Service Charge
Figure 25
Collection of revenue: TOU
With no behavioral changes incorporated into customer's bill, approximately 83 percent of
customers will have an increase in their average monthly bill. However,20 percent of customers
will have less than $15 impact on a monthly basis. Included in Appendix L is the rate design and
bill impact analysis for this change in the customer bill.
D. Large Genera! and Large Power-Primary Service
(Schedule 9P and 19P)
The current rate structure for Large General Primary (Schedule 9) and Large Power Primary
(Schedule 19) service includes a monthly service charge, seasonal time-of-use energy charges,
seasonal demand charges, a summer on-peak demand charge, and a basic load capacity charge.
In addition, Schedule l9 includes a minimum 1,000 kW per month billing demand charge.
IPC-E-18-16 Fixed Cost Report Page 41
ldaho Power Company Rate Design Analysis
Large General and Large Power customers understand the existing rate structure and it is more
aligned with CCOS informed fixed cost collection relative to other customer class rate schedules.
Due to the cost-based nature, the rate structure promotes/favors a high load factor, or better
utilization of the company's system. Although the rate design is more aligned with CCOS than
others, approximately 50 percent of the fixed costs assigned to these classes are collected
through the volumetric energy charge. The company developed its "base" rate design for
Schedules 9P and 19P as informed by the 2017 CCOS study but utilizing the existing service
charge and proportions of revenue collection through the remaining components.
As demonstrated in Figure 26, while these rate classes have rate components that better align
with the company's 2017 CCOS a significant portion of fixed costs are collected through the
energy charge, resulting in over or under collections of the revenue requirement with change in
energy usage.
Collection of Revenue
700%
90%
80%
70%
60o/o
50%
40%
3Oo/o
20%
lOo/o
Oo/o
Cost of Base Case
Service
Schedule 9P
Large General Primary
Cost of Base Case
Service
Schedule 19P
Large Power Primary
r Energy I Demand Service Charge
Figure 26
Collection of revenue: base case
The company evaluated transitioning the current rate design to full CCOS-informed rates to
collect all customer-related costs through the monthly service charge, and all transmission and
fixed production-related charges through a demand charge, all distribution charges through the
BLC, and all variable production-related charges through a time-differentiated energy charge. In
this rate design, the company maintained the current relationship between on-peak demand and
summer billing demand charges as well as the relationship between the time-of-use energy tiers.
Because this rate design is already in use, moving towards CCOS would have no system impact
on metering and billing of Large General and Large Power customers. Figure 27 shows the
results of moving towards a fully CCOS-informed rate design.
Page 42 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Rate Design Analysis
Generally, customers with high load factors are likely to have a decrease in their bill when
moving towards full COS based rates. Conversely, customers with low load factors would
generally see an increase in their bill, reflecting costs associated with their less efficient use of
the system. Additionally, Large General and Large Power customers with high load factors
(generally greater than70 percent and 90 percent, respectively) are likely to see a decrease in
their monthly bill, whereas customers with lower load factors are likely to see an increase in their
monthly bill. Included in Appendix M is the rate designs and the bill impact analysis for this
change in the customer bill.
Collection of Revenue
LOO%
90%
80%
70%
60%
so%
40%
30%
20%
LO%
o%
Cost of Cost of
Service Service
lnformed
Schedule 9P
Large General Primary
I Energy r Demand
Cost of Cost of
Service Service
lnformed
Schedule 19P
Large Power Primary
Service Charge
Figure 27
Collection of revenue: cost of service informed
E. lrrigation Service (Schedule 24)
The current rate structure for Schedule 24has two uniquely defined sg3s61s-"in-season" and
"out-of-season". The current in-season rate structure includes a monthly service charge,
an energy charge and a demand charge. The energy charge utilizes a load-factor pricing
mechanism by separating charges into two energy blocks. The first block charges irrigation
customers a monthly rate per kWh for the first 164 kwh per kW of demand. The second block
charges customers a lower monthly energy rate per kWh for all other energy use to encourage
installation of energy efficient irrigation systems with reduced demand and longer hours
of operation.
The current out-of-season rate structure includes a monthly service charge and an energy charge.
Customers pay a flat energy charge per kWh for all energy used out-of-season.
IPC-E-18-16 Fixed Cost Report Page 43
ldaho Power Company Rate Design Analysis
During the in-season, customers pay a higher monthly service charge than during the out-of-
season; the lower out-of-season service charge encourages customers to continue service
throughout the out-of-season period. However, during the out-of-season period, customers pay a
higher energy charge than in-season to collect more fixed charges through a higher volumetric
energy charge.
The existing rate design for irrigation customers is complex and requires a higher level of
customer sophistication. Seasonal activation, timing of in-season demand and efficient energy
requirements are all components that can impact the customer's bill. The administration of the
current rate design is well tested for the company. Customers with efficient irrigation systems are
well-positioned with the current load-factor pricing mechanism.
For purposes of evaluating potential modifications to rate design, the company developed a
"base" rate design for Irrigation Service, Schedule 24, as informed by the 2017 CCOS study by
utilizing the existing $22 in-season service charge, $3.50 out-of-season service charge and the
current load factor pricing threshold of 164 kwh. As demonstrated in Figure 28, under this type
of rate design, most of fixed costs continue to be collected through the volumetric charge.
Over 80 percent of total revenue collection for this class under the current rate design is through
a volumetric energy charge when nearly 60 percent of the costs to serve this class are fixed
in nature.
Collection of Revenue
700%
90%
80%
70%
60%
50%
40%
30%
20%
70%
0%
Cost of Service
r Energy I Demand
Base Case
Service Charge
Figure 28
Collection of revenue: base case
Page 44 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Rate Design Analysis
lntroduction of BLC
The company evaluated a rate design that moves towards a cost of service informed rate
designed by introducing a BLC that will be assessed in-season. As such, the company's studied
rate design seeks to collect (1) all customer-related costs through a fixed monthly service charge,
(2) summer-production related costs through an in-season demand charge and distribution-
related costs through an in-season BLC charge, and (3) all energy-related, the remaining non-
summer production-related, and all transmission-related costs through energy charges. As
evaluated, the BLC would be charged in-season based on an average of the two highest months
of 15-minute interval demand. Prior to implementation of this type of rate design, the company
would need to educate Irrigation customers on the new BLC charge.
Generally, this rate structure results in higher load factor customers realizing a decrease in their
bill and lower load factor customers experiencing an increase in their bill. As demonstrated by
Figure 29, as customer and demand-related costs are moved out of the energy charge, collection
of the revenue requirement is less exposed to under collecting fixed cost when customers reduce
overall energy consumption.
Collection of Revenue
t00%
90%
80o/o
70o/o
50%
50%
40%
30%
20%
t0%
o%
Cost of Service
r Energy I Demand
BLC
Service Charge
Figure 29
Collection of revenue: BLC
With changes to the rate design, low energy customers are likely to see an increase in their
monthly bill due to the increase in the service charge. Whereas, customers with high energy use
are likely to benefit from the reduction in the in-season energy charge. Additionally, customers
with high load factors (generally, greater than 50 percent) are likely to see a decrease in their
monthly bill, whereas, customers with low load factors (generally, lower than 50 percent) are
likely to see an increase in their monthly bill. High load factor customers are the customers that
are using their systems efficiently, thus, this rate structure encourages efficient energy usage by
IPC-E-18-16 Fixed Cost Report Page 45
ldaho Power Company Rate Design Analysis
Irrigation customers. Additionally, with limited changes to the out-of-season rate structure,
customers with continued service during the out-of-season months and with usage greater than
975 kwh will see a decrease in their out-of-season bill due to a slight increase in the service
charge and a reduction to the out-of-season energy charge. Customers continuing service through
the off-season months with limited to no usage, will see an increase in their out-of-season bills
due to the increase in the service charge. Included in Appendix N is the rate design for irrigation
customers and the bill impact analysis for these changes in the customer bill.
As changes in rate design are contemplated for the Irrigation class, it is important to note that
Irrigation customers are unique among the various customer classes as there is limited ability (in
the short run) to increase or decrease their demand. The pump motors are individually metered
and they are eitherooon" or "off'. Collecting more costs through the demand component of rates
will lower the energy rates and may lower the incentive to conserve or reduce usage.
The unique usage characteristics of the Irrigation customers has contributed to the success of the
Peak Rewards Program where irrigation load is controlled (shut-off) by the company during
times of high summer demand. The Irrigators ability to turn off their pumps, combined with the
nalrow weekday timeframe when summer peak occurs, could result in a significant reduction in
peak system load. One party suggested an alternate rate design could be developed such that if an
Irrigator did not take service during these 3-4 hours then the customer would receive no demand
charges for a given month. Under that type of a structure, if there was 100 MW of Irrigation load
shutting down each weekday during these 3-4 hours, then the system peak load could be reduced
by 100 MW; while the company did not study this type of a rate design, it is important to note
implementation of this type of a rate design would likely require a change to the cost of service
method to ensure adequate fixed cost collection.
Page 46 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Conclusion
Vll. Gonclusion
Idaho Power believes that rate design alternatives that move prices closer to the cost to serve,
such as those CCOS-based rate designs presented in this Report, would lead to significant
improvements in the assignment of fixed costs, provide rate stability, and result in overall fair
and equitable cost allocation in an evolving customer base and service area. As identified in the
company's 2017 CCOS study and changes suggested by parties, the CCOS suggests the
company's current cost strucfure is 50 percent or more fixed cost related for every customer
class. Over the last 20 years, Idaho Power has continued to propose rate designs in rate
proceedings that are more reflective of the cost of producing and delivering energy informed by
the CCOS. By more accurately reflecting the true cost of service at a given place and time, these
alternative rate designs help customers become informed consumers of electricity, which may in
turn help improve efficiency and effectiveness of the grid. The company is committed to
establishing rate designs for customers that are fair and sustainable into the future. Idaho Power
appreciates the collaborative process with parties in this case, which has helped influence this
Report and the opportunity to provide the Commission with a comprehensive fixed cost study,
including CCOS and rate design options.
IPC-E-18-16 Fixed Cost Report Page 47
ldaho Power Company Conclusion
Page 48 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Appendix A
Appendix A
Scope of Attributes to be Studied (Attachment A-Staffs 4130119 Report, IPC-E-18-16)
Attachment A: Base Case Rate Designs
IPC-E-18-16: Idaho Power's Fixed Cost Recovery Docket. Explore fixed-cost recovery in basic
charges and other rate design options.
No. Rate Design Description and Comments
1 Company's current rate
designs
Single fixed charge
Volumetric charge only
Demand charge only
Time differentiated rates
Time differentiated demand
Time of use rates, based on
both time differentiated cost of
energy and demand
8 Connected load based charge
9 Peak rebates
Company's current rates will be studied as base cases
All customers within class pay the same fixed charge. Use as an end-point.
Rates based only on volume consumed. Current Schedule 42 (Traffic
Control/Signal Lighting) rate. Use as an end-point.
Customers pay only a demand charge. Use as an end-point.
Volumetric rate that varies with time of day, day of week, or season. Note that
Schedule 5 incorporates an optional time-of-use volumetric rate. Schedule 19
and 24 (Large Power Service and lrrigation) use a three-part rate structure
that incorporates TOU or seasonal volumetric rates.
Demand charge assessed at peak times (CP, NCP, etc.).
Volumetric rate that varies with time of day, day of week, or season. lncludes
both marginal energy cost and demand components. Will include PeaUOff
Peak Price Ratio (POPP)rates.
This is a type of demand charge that is based on service size (100 A,
200 A, etc.).
This would be a rate structure-specific proposal. Rebates can be applied to
volumetric or demand charges. How do we characterize and study it?
2
3
4
5
6
7
Updated April 15, 2019
IPC-E-18-16 Fixed Cost Report Page 49
ldaho Power Company Appendix A
Attachment B: Rate Design Attributes
IPC-E-18-16: Idaho Power's Fixed Cost Recovery Docket. Explore fixed-cost recovery in basic
charges and other rate design options.
No. Attribute Description and Comments
1
a
lmpact on Fixed Cost Recovery
Revenue stability
Credit risk
Relationship with FCA/PCA
The ability of each rate design to
recover the Company's fixed costs
lmpact to future cost causation
Billing lmpacts to Customers
lmpact across class
Low income impact
Stability for customers
Gradualism
Price Signaling and Behavior
Conservation
b. Controllability
Peak reduction, or other measures that
result in decreased need to invest in
fixed plant
Predictability
Simplicity
Fair, Just, and Reasonable
Fairness of the specific rates in the
apportionment of total costs of service
among the different customers
Avoidance of "undue discrimination" in
rate relationships
Other Considerations
lmplementation Costs
Rate design's ability to recover Company's fixed cost.
Sensitivity to weather, decreasing customer demand, etc.
Effectiveness in yielding total revenue requirements under the
fair-return standard.
Effects on cost of capital.
All rates can be set to recover the Company's fixed costs. This
is the exercise undertaken in the general rate case. lntra-class
cross subsidization.
Study the impact across different usage patterns, including
different volumetric patterns and different demand patterns,
including consideration for outliers.
To the extent possible, study impacts to low income customers
in older homes, apartments, etc.
Energy efficiency, including temporal effects such as energy
and plant deferrals as functions of time. Efficiency of rate
classes and rate blocks in discouraging wasteful use of service
while promoting all justified types and amounts of use in the
control of the total amounts of service supplied by the
Company.
Degree to which customers can control billing determinant.
Actionable signal.
Degree to which customers are incented to reduce consumption
that drives the need to invest in new capital.
Actionable signal.
Ability of customers to understand and act on a signal, and
freedom from controversy about proper interpretation.
Basic regulatory standard.
b
c
d
e.
2
a.
b.
c.
d.
3
a.
c
d.
e.
4
a.
b.
5
a.
Updated April 15, 2019
Page 50 IPC-E-18-16 Fixed Cost Report
Appendix B
Developmenl of 2017 Results of Operations
The 2017 Results of Operations (ROO) study, l2-months ending December 31, 2017, was
developed using a methodology similar to that approved in the company's last general rate case,
Case No. IPC-E-l l-08 (2011 rate case). However, unlike the 201I 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 2017 normalized
revenues and the 2017 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 31,201728:
a The company began with actual, audited and reported to the U.S. Securities and
Exchange Commission,20lT financial data (2017 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.
a Next, the company made standard regulatory adjustments, or adjustments in conformance
with prior Idaho Public Utilities Commission (Commission) orders, to the 2017 Actuals.
The adjustments, which are explained and quantified in further detail below, included the
removal of the following:
o General advertising expenses
o Specific memberships and contributions
o Certain management expenses, and other exclusions that, although justified for
business purposes, have historically been viewed by the Commission as more
appropriately funded by shareholders than customers and therefore are not
recoverable through the company's rates
o Prepayments
o A portion of incentive compensation,
o Financial impacts of the Idaho and Oregon Energy Efficiency Rider revenues and
expenses
o Plant held for future use to remove structures and specific properties for which the
furure use is uncertain
28 This document was initially provided to parties in Case No. IPC-E-18-16 as part of a response to discovery. The
references to "attachments" contained within this summary reference supporting workpapers provided in the
discovery response.
IPC-E-18-16 Fixed Cost Report Page 51
ldaho Power Company Appendix B
ldaho Power Company Appendix B
a
a
In addition, Idaho Power adjusted the 2017 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 90
historical water conditions (1928-2017). The term "net power supply expense" refers to
the sum of the following Federal Energy Regulatory Commission (FERC) accounts: fuel
expense (FERC Accounts 501 and 547), and purchased power expenses (FERC Account
555), minus surplus sales revenues (FERC Accotnt 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. [n 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 established recovery mechanisms in place for the Valmy and
Boardman coal-fired plants, Idaho Power has removed all cost of service components
associated with these coal plants that are recovered through the levelized revenue
requirement mechanisms. Recognition of the Boardman and Valmy related levelized
revenue requirement is applied as an adjustment to the class cost of service process as
described in Appendix C.
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 Attachment la. The JSS is a three-step process-the classification,
functionalization, and allocation of costs-that separates costs among jurisdictions. [n 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.
Page 52 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Appendix B
The classification, functionalization, and allocation of costs was performed in accordance with
the approved20ll rate case methodologies 29. 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 2017 normahzed revenues and the 2017 cost of service components.
Jurisdictional Separation Study for the 12-Months Ending
December 31 ,2017
The following is a description and quantification of adjustments made to 2017 Actuals in the
order they appear in the JSS and a brief description of how the adjusted2}l7 Actuals were
allocated to each jurisdiction (Attachment lb includes the workpapers that support
the adjustments):
a 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 201I rate case.
Table I -Electric Plant-In-Service
o Table 1 reflects Idaho Power's 13-month average electric plant-in-service values,
excluding Valmy and Boardman, at December 3 1,2017. 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 l2-
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 l3-month average at
December 31, 2017 . 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
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
goups based on the related plant account in Table l. Amortization of other utility
a
o
2e 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.
IPC-E-18-16 Fixed Cost Report Page 53
ldaho Power Company Appendix B
a
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, and283),
materials and supplies (FERC Accounts 154 and 163), and IERCo rate base
components reflect the l3-month average. However, other deferred programs
reflect the account balances as of December 31, 2017.
o A number of adjustments are included in Table 3:. Fuel stock inventory includes only required fuel stock inventory of
$33,559,334.. Removal of the following from rate base:
. $16,865,877 inprepayments.. $1,921,626 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.o $10,769,932 associated with the Siemen's long-term program
contract regulatory asset that received deferred rate base treatment
with IPUC Order No. 33420.o $85,531 of plant that was determined in the 201 I rate case to no
longer be used and useful at the Bridger Coal plant.
o Additions and deletions to rate base were allocated under a number of different
methodologies: (1) customer advances for construction were directly assigned to
customers by jurisdiction, (2) accumulated deferred income taxes are allocated by
plant, customer advances for construction, or labor, (3) materials and supplies by
their respective plant allocators, (a) fuel inventory on the basis of energy, (5)
components of IERCo on energy, and (6) Commission-ordered deferred
investments were either directly assigned to a specific jurisdiction or allocated
based on energy.
Table 4-Operating Revenues
o Operating Revenues includes an adjustment of ($ 128,706,794) to 2017 Actuals to
reflect the normalization and annualization of revenues and an adjustment of
(553,352,221) for the removal of revenues associated with the Valmy and
Boardman plants. In addition, an adjustment of $2,400,560 to FERC Account 447,
Opportunity Sales, was made to reflect the normalized NPSE results from
AURORA. Finally, $39,240,688 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 eachjurisdiction in proportion to generation-level energy use.
Other Operating Revenues were allocated in a manner that offsets related
Page 54 IPC-E-18-16 Fixed Cost Report
a
ldaho Power Company Appendix B
a
allocations of rate base, or where a particular revenue item could be associated
with a specific jurisdiction, directly assigned.
Table 5-Operations and Maintenance Expenses
o The following is a summary of the adjustments made to 2017 Actual
O&M expenses:r 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 2017 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.. $39,240,688 in Idaho Energy Efficiency Rider expenses (FERC Account
908) were removed.. $5,3 16,496 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.. $110,743 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.r d deduction of $673,383 was made for general advertising expenses,
certain memberships and contributions, senior management expenses, 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. ln general, the basis for
each allocation is identifiable with the source code listed in the JSS provided as
Attachment 1a. 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 "CWr" prehx. For each functional group, the labor
component was separately allocated in accordance with the detail provided in
Table l3-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 qnd 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.
a
IPC-E-18-16 Fixed Cost Report Page 55
ldaho Power Company Appendix B
a
a
a
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 Creditso No adjustment was made to 2017 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 Stateo 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 l3 through lS-Development of Labor Related Allocator, Allocation Factors, and
Allocation Factors-Rattoso No adjustment was made to 2017 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.
o
The summary of the JSS results are presented on page 1 of Attachment 1a. The development of
the Idaho jurisdictional ROO is presented in the column entitled "Idaho Retail".
When comparing the difference between 2017 normalized revenues and the 2017 cost of service
components, the resulting Idaho consolidated operating income is $219,293,371 (line 31).
Page 56 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Appendix C
Appendix C
Class Cost of Service Process Guide
To help support the evaluation of the Class Cost of Sentice 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's last rate case. The process guide is unchanged except to highlight
new methodolog,, since the 201I rate case. All additions are denoted by two asterisks (**) at the
start and end of the addition with added text in italicixed, bold font.
The following is a technical description of Idaho Power'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.
l. 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 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.
IPC-E-18-16 Fixed Cost Report Page 57
ldaho Power Company Appendix C
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.
G. 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.
!!. Assign Module and Functionalized Gost 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 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.
Page 58 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Appendix C
lll. 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
classilied with the same demand and energl allocation as steam production plants. For
classijication of costs related to all natural gas-ftred production plants, a new allocation factor
was developed reJlecting the weighting of all gas-Jired 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
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 generalrate 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
IPC-E-18-16 Fixed Cost Report Page 59
ldaho Power Company Appendix C
lV. 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 functionalizedto demand
production.
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
Page 60 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Appendix C
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 lncome, and
lncome 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 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 on-site generation customers drawtng €fi€rpt and requires modijication to the
derivation of peak demand. At the time of system peak, on-site generation service points
registering negative demand are set to a demand value of zero. Because the valae for
Residential and Small General on-site generation will be established independently through
the Value of Distributed Energt Resource (VODER) in Docket IPC-E-18-15, this adjustment
is necessary to avoid the double counting of benejits related to excess generation at the time of
system pealc**
IPC-E-18-16 Fixed Cost Report Page 61
ldaho Power Company Appendix C
B. Margina! Gost Usage
While the 3CPll2CP 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 pu{poses. 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 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 ofdeveloping allocation factors and not for purposes of
developing the company's revenue requirement.
C. Production Plant Gost 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 l2
monthly coincident demands (12CP), without marginal cost weighting. Using an un-weighted
l2CP 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
Page 62 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Appendix C
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. [n recognition of that fact, those two categories have been 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. **Bennett Mountuin and Danskin
power plants are** used to serve peak demands, **and the compuny's Langley production
resource is considered a baselosd 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 "DIOBNS" 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 Dl0BS and Dl0BNS represent the non-weighted
IPC-E-18-16 Fixed Cost Report Page 63
ldaho Power Company Appendix C
average twelve coincident peak demands for the summer and non-summer seasons respectively.
The allocator Dl0P 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 Dl3 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 Dl3. 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 evuluate bi-directional capacity
requirements, the Residential and Small General on-site generation customers' demand values
were measured on an absolute value basis to derive the non-coincident group peak demand.**
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 Gost Allocation
The energy-related cost allocators, El0S and E1ONS, 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 EIONS allocators used in this study. This averaging approach is
consistent with the methodology used in the derivation of the demand-related allocation
factor Dl3.
Page 64 IPC-E-18-16 Fixed Cost Report
I
ldaho Power Company Appendix C
**Normalized energt values for the Residential and Small General on-site generation
customer classes are net hourly delivered energy. The value for Residential and Small General
on-site generation hourly excess generation will be established independently through the
VODER in Docket IPC-E-18-15. **
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.
F. State and Federal lncome 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.
Vl. 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 mutch the FC Module's Revenues from Rutes with the ldaho Results of Operations'
exclusion of Boardman & Yalmy levelized revenue, the FC Module includes an adjustment to
esch class's cost of service results to add back each plant's levelized revenue requirement.
Derivution of allocation to each class followed established Assign Module classiJication and
functionalization methodologt for each plant. To allocate production baseload demand und
energt to each class, estublished FC Module allocation factors were utilized,*
IPC-E-18-16 Fixed Cost Report Page 65
ldaho Power Company Appendix C
Page 66 IPC-E-18-16 Fixed Cost Report
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ldaho Power Company Appendix E
Appendix E
Scenario No. 1 lndividual Modification lmpacts
L40%
L20%
1.OO%
80%
60%
40%
20%
0%
Residential Residential
On-Site
Small Small General Large
General On-Site General
Large lndustrial lrrigation
General P/T
P=th
o
=Cc)
OJL.(f,
OJ.=fo0lE.
I COS w Scenario 1 - Modification 1
L40%
L20%
L00%
80%
60%
40%
20%
o%
Residential Residential
On-Site
Small Small General Large
General On-Site General
Large lndustrial lrrigation
General P/T
P
=tJl
o
=cq)
oL'If
c).=fooG
I COS w Scenario 1- Modification 2
IPC-E-18-16 Fixed Cost Report Page 69
ldaho Power Company Appendix E
Residential Residential
On-Site
Small Small General
General On-Site
Large lndustrial lrrigation
General P/T
La rge
General
P=-ctJl
OJfco
oL
E(u
.=fu(u
G.
740%
720%
700%
80%
60%
40%
20%
o%
t40%
t20%
LOO%
80%
60%
40%
20%
o%
r COS Scenario 1 - Modification 3
Residential Residential
On-Site
Small Small General Large
General On-Site General
Large lndustrial lrrigation
General P/T
P
=-Cth
o)fCo
o)L
Eo).=fo
o)G
r COS Scenario 1 - Modification 4
Page 70 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Appendix F
Appendix F
Scenario No. 2 lndividual Modification lmpacts
Residential Residential
On-Site
Small Small General Large
General On-Site General
Large lndustrial lrrigation
General P/T
PF
=th
o
=-o)
oL
E
O).:
Joq)
G,
L40%
t20%
LOO%
80%
60%
40%
20%
0%
L40%
t20%
1.OO%
80%
60%
40%
20%
0%
I COS ,,q Scenario 2 - Modification L
Residential Residential
On-Site
Small Small General Large
General On-Site General
Large lndustrial lrrigation
General P/T
v
=-Crt1
o):lc
0.)
OJLE
OJ.=
=uoG.
r COS Scenario 2 - Modification 2
IPC-E-18-16 Fixed Cost Report Page71
ldaho Power Company Appendix F
Residential Residential
On-Site
Small Small General Large
General On-Site General
Large lndustrial lrrigation
General P/T
=tJ1
o
=go
oL
Eo.=
=oo&.
1.40%
L20%
L00%
80%
60%
40%
20%
o%
140%
L20%
700%
80%
60%
40%
20%
o%
r COS "E Scenario 2 - Modification 3
Residential Residential
On-Site
Small Small General Large
General On-Site General
Large lndustrial lrrigation
General P/T
P=-th
aJ:lcqJ
(u
T)o.=fuod.
r COS Scenario 2 - Modification 4
Page72 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Appendix G
Appendix G
Revenue Requirement and Fixed-Variable Proportion Cost of Service Analysis by Class
Residential
ssooM
s4s0M
$4ooM
Sssotvl
s3ooM
s2s0M
s20oM
s1s0M
s10oM
ss0M
solv
5.7%
20.4%20.4%
21.2%L3.3%
Reven ue Cost Scenario 1 Scenario 2 Scenario 3
I Energy IEnergy "Fixed" I Demand Customer
Residential On-Site Generation
s1.6M
s1.4M
L6.8%9.L%16.8%
Sr.zvt
78.6%
$1.0M
so.8M
So.swt
so.4M
so.2M
so.oM
Reven ue Cost Scenario 1 Scenario 2 Scenario 3
r Energy IEnergy "Fixed" r Demand
94.3%
48.8%
33.9%38.O%
17.8%
93.3%
3t.8%39.3%
L5.4%
IPC-E-18-16 Fixed Cost Report
Customer
Page 73
45.7%40.8%
38.0%
45.7%
1,6.1%
5L.4%
42.0%
46.0%
44.8o/o
5L.4%
L6.4%
ldaho Power Company Appendix G
Small General Service
s18M
s16M
s14M
srzrvr
sloM
ssrvr
sswr
S+w
szwr
Sow
Reven ue Cost Scenario 1
IEnergy "Fixed" r Demand
Scenario 2 Scenario 3
I Energy Customer
Small General Service On-Site Generation
So.o+rvt
s0.04M
so.03M
so.03M
s0.02M
so.o2M
so.o1M
so.o1M
So.ooM
Reven ue Cost Scenario 1 Scenario 2 Scenario 3
r Energy !Energy "Fixed" I Demand Customer
89.2%
42.6%27.3o/"30.o%
39.3o/"23.7%28.9%
LO.7%
Page74 IPC-E-18-16 Fixed Cost Report
108%
42.7%
3A.f/o
43.5%
26.4%
32.5%
24.9%
42.7%
30.1o/o
12.9%
74.4%
1L.7o/o
883%
24.7%
tl 10/
27.3o/o
43.8%
76.6%
44.O%
24.7o/o
52.2%
12.4%
ldaho Power Company Appendix G
s2s0M
Large General Service - Secondary
2.9o/o 3.4%
s.1%4.9%
s20oM
slsoM
s100M
ssoM
Sow
Revenue Cost Scenario 1
IEnergy "Fixed" I Demand
Scenario 2 Scenario 3
I Energy Customer
Large General Service - Primary and Transmission
s4oM
s3sM 2s%
2.7%2.7%
25%2.8%
s3oM
s2sM
s20M
slsM
SloM
ssM
s0M
Revenue Cost Scenario 1
I Energy "Fixed" t Demand
Scenario 2 Scenario 3
I Energy Customer
80.5%
58.60/o
5L5%
24.5%
69.8%59.3%
46.7%52.O%
24.2%
IPC-E-18-16 Fixed Cost Report Page 75
48.7%
46.3o/"
43.4%
38.0%
48.7%
21.8o/o
27.7%
38.2%
50.60/o 45.3o/o so.6%
22.5%
16.6%
ldaho Power Company Appendix G
s0M
$1GoM
s140M
s12oM
slooM
Saov
SsoM
s40M
s2oM
s2s0M
s2ooM
s1s0M
slooM
ssoM
o.3%
Reven ue
L.6%
Revenue
Large Power Service
0.5%
05%o.5%
Cost Scenario L Scenario 2
! Energy IEnergy "Fixed" I Demand Customer
lrrigation
3.7%
2s%
3.7%
Cost Scenario 1 Scenario 2
I Energy I Energy "Fixed" r Demand Customer
o5%
Scenario 3
3.7%
Scenario 3
Sorv
75.3%65.7%
58.3%52.7%
27.1o/o
77.5%
36.5%40.2%
20.3%
Page 76 IPC-E-18-16 Fixed Cost Report
24.4o/o
46.8o/o 41.2%
33.80/o
46.8%
25.6%
20.9%
56.t%
603%48.3%
49.2%
s6.7%
19.8%
ldaho Power Company Appendix H
Appendix H
Time of Use Period Selection
To determine the on-peak demand and on-peak time periods that were used to develop the
Residential and Small General Service rate designs, the company gathered system load data for
its entire network each hour over the past five years (2014-2018). Because the company does not
weather normalize data on an hourly basis for analyical purposes, it was prudent to include a
wider scope than just one year of data to help alleviate annual impacts of weather variation from
normal climatological conditions.
Over the cycle of a day the company chose an hourly reading that was 90 percent or greater than
the peak hour as a proxy for "peak level" demand on the system. The analysis of volumes 90
percent of the daily peak was analyzed using several measurement techniques. (1) Data was
sorted by month and average hourly reads within that month for that hour, (2) data was sorted by
month and maximum hourly reads over the five-year data collection period within that month,
and (3) only weekend and FERC holidays were removed from data analysis. On an annual basis
using scenario ( I ) stated above it was found that 207 hours of the year would fall under the scope
of 90 percent of the peak value for the day. Histogram analysis telegraphed to the company that
all the 207 hours occurred during hour ending 15 to hour ending 23 (see figure below). A similar,
but not identical, pattern emerged under all three scenarios mentioned above. These results
helped inform the recommendation to define the summer on-peak period of 3 p.m. to l0 p.m.
during weekdays.
Number of
Occurances
50
Histogram of Occurances of Hours 90% of Peak
(Summer)
40
30
20
10 llllr
18 19 20 21. 22 23 24
0
7 2 3 4 5 6 7 8 9 10 11 12 13 1.4 15 16 17
Hour Ending
IPC-E-18-16 Fixed Cost Report Page 77
ldaho Power Company Appendix H
A similar approach was taken to the non-summer time period, the outcome provided for two on-
peak time periods for Residential and Small General customers time of use on-peak time periods
shall be defined as 7-l I a.m. and 5-9 p.m. during weekdays.
Histogram of Occurances of Hours 90% of Peak
(Non-Summer)
70
850Iccqn
3
840
o30
OJt20:2 1"0
0 t
7 10
ll,r lr
2t 22 23 241234s611 72 13 14 15 16 17 18 19 20
Hour Ending
Page 78 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Appendix I
Appendix I
Schedules 1 andT Base Case Compared to Three-Part, Tiered Rates
Schedule 1
Base Case
Tlered Volurrtrlc Rates
Studaed Case
Three-Part Tiered
Trers
Energy Charge
Surnner Non-Sumrpr Tiers
Energy ChargeSurnnpr Non-Sumrner
0-800 kwh
801-2,000 kwh
Over 2,000 kwh
$0.083026
$0.099835
$0.1 18597
$0.077146
$0.085051
$0.0941 92
0-800 kwh
801-2,000 kwh
Over 2,000 kwh
$0.049863
$0.059957
$0.071225
$0.046331
$0.051079
$0.056569
Sunrrpr Non-Surrrpr Surrrpr Non-Sunrrer
SeMce Charp $5.00 $5.00 Servlce Gharge
BLC
On-Peak kW
s17.28
$1.15
$5.41
$'t7.28
$1.1s
N/AArerage Monthly Consumption
Arerage On-Peak kW
Awrage BLC
Awrage Bill lncrease
Arerage Bill Decrease
Arerage O,erall Bill lmpact
956
5
9
$8.82 (263,739 customers)
-$16.22 (160,677 customers)
-$0.66
Avg $ Change
(ilonthly)
Number of yo ol Cunuaative
Custorersr Custorprs oA
Averag6
Base Case
Bl[
Average
Studaed Case
Btlt
Avorage Avorage
illonthly Ditr Annual Dltr
o
=iE
I
EDI
GT $100
GT $25 LE $100
GT $15 LE $25
GT $10 LE $15
GT S5 LE $10
17
1,422
22,876
82,605
90,017
0.00%
0.UYo
5.39%
19.46Yo
21.21o/o
0.00%
0.UYo
5.73o/o
25.1gyo
46.40v.
$128
$62
$35
$40
$s8
$80s
$9s
$52
$52
$66
$678
$33
$17
$12
$8
$8,1 33
$401
$207
$147
$91
GT $0 LE $5 66,709 15.72% 62.12% $76 $79 $3 $32
No Chango 0 207 0.05% 62.17% $84 $84 $0 $0
g
iE
oiJ
GT SO LE $5
GT $5 LE $10
GT $10 LE $15
GT $1 5 LE $25
GT $25 LE $100
GT $100
45,823
31,778
22,822
27,953
31,148
1,051
72.960/.
80.45%
85.83%
92.41o/o
99.75o/o
100.00%
$94
$111
$1 28
$1s2
$221
$578
$92
$104
$1 16
$132
$180
$423
-$2
-$7
-$12
-$19
-$41
-$15s
-$28
-$88
-$148
-$2U
-$492
-s1,860
1 Customers with less than 12 months of data were excluded from the bill impact analysis.
40%
_a 35%
o)t 30%(U
? 2s%
2 zowoE 75%oR 70%
=us%
0%rrrrlll h
<- Sloo -s25 to - -s2s to -srO -$10 to $0 s0 to s10 s10 to s2s s2s to s100 > s100
s10o
r All Customers LIHEAP I Weatherization
Percentage of Residential customer average monthly impact-base case to three-part, tiered rate
IPC-E-18-16 Fixed Cost Report Page 79
*
On-Peak 3-10 PM
10.80%
7.49Yo
s.38%
6.59%
7.34Yo
O.25Yo
Appendix I
Schedule 7
Base Case
Tiered Volumefic Rates
Studled Gas
ThreePart Tlered
Tiers
Energy Charge
Summer J{onSummer Tiers
Energy Charye
Summer NonSummer
0-300 kwh $0.0921 l3
$0.1 09707
$0.0921 13
$0.096645
0-300 kwh
O\€r 300 kwh
$0.043830
$0.046368
$0.043830
$0.047635O\er 300 kwh
Summer Non-Summer Summer NonSummer
Servico Charge $5.00 $5.00 Service Charge
BLC
OnPeak kW
$18.52
$0.80
$4.56
$18.52
$0.80
N/AA\erage Monthly Consumption
A\erage On-Peak kW
Awrage BLC
Average Bill lncrease
Arerage Bill Decrease
Arerage Orerall Bill lmpact
381I
4
$10.30
-$14.63
$0.50
Summer
(15,952 customers)
(10,331 customers)
Onfeak 3-10 PN/
Avg $ Change Number of
Cuslomersr
o/o ol
Cu$omers
Average
Cumulative Base Case
Average
Studied Case
Biil
Average
Monthlv Difr
Average
Annual Difr(Monthlv)o/"
I
o
o
CD
=
GT $100
GT $2s LE $1 00
GT $1 5 LE $25
GT$1OLE$15
GT$5LE$10
GT $O LE $5
25
192
1,230
7,235
4,'t21
3,149
0,10o/o
0.730/o
4,680/o
27.52o/o
'15.680/0
11.98%
0.10%
0.83%
5.50%
33.02%
48.70%
60.68%
$41
$29
$13
$11
$24
$36
$194
$6e
$31
$24
$32
$39
$1 s3
$41
$17
$13
$8
$3
$1,836
$488
$208
$1 52
$91
$31
No Change 0 7 0.030/6 60.7O0/o $40 $40 $o $o
I
o
o)oJ
GT $O LE $5
GT$5LE$10
GT$1OLE$15
GT $1 5 LE $25
GT$25 LE $100
GT s1 00
2,566
2,058
1,678
2,147
1,881
1
9.760/o
7.83%
6.38%
8.17%
7.15%
0.00%
70.46%
78.29%
84.67%
92.84%
100.00%
$48
$s9
$69
$86
$121
$832
$45
$52
$57
$67
$86
$652
-$2
-$7
-$12
-$20
-$36
-$ 180
-$29
-$89
-$ 148
-$234
-$427
-$2,164l Customerswithlessthanl2monthsofdataweree)<cludedfromthebill impactanalysis
q 30%
o
E
; 20%f-oug+QO(oot * lO%hoF(o-=
c0)?. o%oL <- s100 -Szs to
s100
-S2s to -S10 -St0 to 0 S0 to S10 S10 to S2s S2s to 5100 > 5100
Average Monthly Change
Percentage of Small General customer average monthly bill impact base case to three-part, tiered rate
Page 80 IPC-E-18-16 Fixed Cost Report
ldaho Power Company
ldaho Power Company Appendix J
Appendix J
Schedules 1 and 7 Base Case compared to Time of Use (Cost-Based) Rates
Schedule 1
Base Caeo
Tlered VolurEtrh Riles
Studled Case
TOU (Cost Based)
Tiers
Energy Charge
Survrrr Non-Sunrrpr
Energy Charge
Surrrpr Non-Sunrrpr
0-800 kwh $0.083026 $0.077146
801-2,000 kwh $0.099835 $0.085051
Over 2,000 kWh $0.1'18597 $0.09.192
On-Peak
Off-Peak
$0.090098
$0.087271
$0.051747
$0.050780
Sunrrrr Non-SuflflEr
Sunrrpr Non-Surnpr Service Charge
BLC
$17.28
$1.1s
$17.28
$1 .15Service Charge $5.00 $5.00
Arerage Monthly Consumption
Awrage BLC
Arerage Bill lncrease
Arerage Bill Decrease
Arerage O€rall Bill lmpact
956
I
$8.80 (285,029 customers)
-$17.54 (1 39,393 customers)
$0.15
Summer Non-Summer
On-Peak
Ofi-Peak
$10PMIvl-F 7-11 AMtvlF,
5-9 PM tvtF
Al other hours
Awrag6
Avg 3 Change Number of Yo ol Cumrtdhrc Base Case(ilonthlyl CuEtorprsr CustorErs % Bal!
Average
Studled Case
BII!
Arerage
lulonthly Dlfi
Average
Arrnml Difi
c,
o
o
oE
GT $100
GT $25 LE $100
GT $15 LE $25
GT $10 LE $15
GT $5 LE $10
GT $O LE $5
13
1,028
12,029
105,800
1U,773
61.300
0.00%
0.24Yo
2.83Yo
24.93v,
24.69V.
14.44o/o
0.00%
0.25o/o
3.08o/o
28.01o/o
52.69Yo
67.14o/o
$128
$72
$34
S4o
563
S84
$973
$106
$s1
$s2
$70
$86
$84s
$34
$17
$12
$8
$3
$10,146
$413
$205
$14s
S93
s33
No Chanse 0 169 o.uoh 67.18yo $94 $94 $o $o
3a
o
'oJ
GT $O LE $5
GT $5 LE $10
GT $10 LE $15
GT $15 LE $25
GT $25 LE $100
GT $'100
38,7U
26,435
18,900
24,350
29,570
1,327
9.13v.
6.23%
4.45o/o
5.74o/o
6.97o/o
0.31%
76.30o/o
82.53o/o
86.98%
92.72v.
99.69%
100.00%
$101
$1 18
$134
$156
$222
$543
$99
$111
$122
$1 37
$180
$386
'$2
-$7
-$12
-$19
-v2
-$157
-$28
-$88
-$148
-$234
-$s04
-$1,880I Customers with less than 12 months of data were excluded from the bill impact analysis.
40%
T 35%
E zotr!* 25o/oE
! zooto
OJE 75o/ooR 70%
=,s%
0%
<- Sroo -s25 to - -s2s to -s10 -sro to so s0 to s10 s10 to s2s s2s to s100 > sroo
s100
I All Customers LIHEAP I Weatherization
Percentage of Residential customer average monthly impact-base case to TOU
IPC-E-18-16 Fixed Cost Report Page 81
ldaho Power Company Appendix J
Schedule 7
Base Case
Tiered Volumetric Rat6 Dedgn
Studled
TOU (Cort Baed)
Tiers
Energy Charge
Summer NonSummer
Energy Charge
Summer Non€ummer
0-300 kwh
Over 300 kwh
$0.0921 13
$0.1 09707
$0.092113
$0.096645
On-Peak
Off-Peak
$0.075639
$0.072971
$0.047s26
$0.046360
Summer J{onSummer Summer NonSummer
Servlce Charge $18.52 $18.52Seryice Charge $5.00 $5.00
BLC $0.80 $0.80
A\erage Monthly Consumption
Awrage BLC
Awrage Bill lncrease
Arerage Bill Decrease
Awrage Owrall Bill lmpact
381
4
$9.90 (16,494 customers)
-$13.57 (9,792 customers)
$1.16
Summer Jton€ummer
OnPeak
OffPeak
3-10 PM t\,|-F 7- 1 AI\ll t\AF
5.9 PM MF
Al other hours
Avg $ Change
(t{onthly}
Number ol
Customersi
%ot
Guslomers
Avera96
Cumulatlve Bao Cata% Bll!
Average
Studled Cae
BiII
AYerage
Uonthly Dlfi
Average
Annual Dlfi
3o
os
-9-
GT $1 00
GT $25 LE $100
GT $1 5 LE $25
GT $10 LE $1 5
GT$5LE$10
GT $O LE $5
11
137
871
7,766
4,429
3,280
o.o4%
0.52%
3.31Yo
29.540/o
16.85%
12.48%
0.04%
0.56%
3.88%
33.42%
50.26%
62.74%
$30
$30
$12
$11
$25
$38
$206
$71
$30
$23
$33
$41
$1 76
$41
$17
$13
$8
$3
$2,114
$492
$206
$1 s2
$92
$31
No change 0 4 o.o20h 62.750/o $51 $sl $0 $0
g
E
oioJ
GT $O LE $5
GT$5LE$10
GT $10 LE $1 5
GT $15 LE $25
GT $25 LE $100
GT $100
2,639
2,056
1,553
1,979
1,564
1
10.04%
7.82%
5.91%
7.53%
5.95%
0.00%
72.790/o
80.61%
86.52%
94.05%
100.00%
100.00%
$51
$62
$75
$92
$1 26
$832
$48
$55
$62
$72
$s2
$604
-$2
-$7
-$ 12
-$1e
-$34
-$228
-$29
-$89
-$ 149
-$233
-$409
-$2,734
1 Customers with less than 12 months of data were e)cluded from the bill impactanallrsis
q 30%
c)
Et 20%
=-oug+oOGa*LO%boFro=
(J?. o%
OJc <- Sloo -Szsto- -S2sto-S10 -S10to0 S0toS10 510to525 S25to5100 >5100
s100
Average Monthly Change
Percentage of Small General customer average monthly bill impact base case to TOU (cost based)
Page 82 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Appendix K
Appendix K
Schedules 1 and 7 Base Case compared to Time of Use (5:1 ) Rates
Base Case
Tiered Volurptric Rates
Studied Casa
TOU (5:1)
Trers
Energy ChargeSunmr Non-Sumrner
Energy Charge
Surmr Non-Sumrner
0-800 kwh
80'1-2,000 kwh
Over 2,000 kWh
$0.083026
$0.099835
$0.077'146
$0.085051
s0.094192
On-Peak
Off-Peak
$0.275066
$0.0v708 $0.054708
N/A
s0 1'r8597 Surrrpr Non-Sunrrrr
Sunxrnr l{on-Surnpr Service Charge $17.28 $17.28
Service Charge $5.00 $s.00
Summer Non-Summer
Arerage Monthly Consumption
Alerage Bill lncrease
Arerage Bill Decrease
Arerage O,erall Bill lmpact
956
$9.87 (288,460 customers)
-$18.59 (135,962 customers)
$0.7s
On-Peak
Of-Peak
3-10 PM t\il-F N/A
All other hours
Aw I Ghange
(itonthly)
Nurter of
Cudonprsr
oh ol
Customrs
Cumllatlve
Yo
Average
Base Care
Bix
Average
Studled Gase
BiI
Average
Monthly Diff
Anerage
Annual Dlfi
$322
$202
$148
S93
932
$27
$17
$12
$8
$3
$95
$74
$64
$70
$82
$68
$s7
$s2
$63
$80
1A
o
oEo
I
-$2
-$7
-$12
-$20
-$42
g
iE
o
'o
rrrlll
GT $25 LE $100
GT $1 5 LE $25
GT $10 LE $15
GT $5 LE $10
GT $O LE $5
61
35,669
117,437
85,058
50,159
0.01o/o
8.40o/o
27.67v.
20.uv.
11.820/0
0.01%
8.42Yo
36.090/o
56.13%
67.95yo
l{o Chango 0 1s6 0.O4% 67.98% $88 $88 $0 $0
GT $O LE $5
GT $5 LE $10
GT $10 LE $15
GT $15 LE $25
GT $25 LE $100
33,807
24,617
18,672
25,429
32,063
7.97o/o
5.80%
4.40v.
5.99%
7.550k
75.950/0
81.75Yo
86.15%
92.14o/o
99.69%
$95
$111
$126
$148
$214
$93
$104
$1 14
$129
$172
-$28
-$89
-$149
-$23s
-$5oo
cT $100 1,300 0.31% 100.00% $542 $386 -$1s6 -$1,869
1 Customers with less than 12 months of data were excluded from the bill impact analysis.
50%
40%
30%
20%
70%
0%
s10o -s25 to - -s2s to -s10 -sro to so so to sro s10 to s2s s25 to s100 > s100
s10o
I All Customers LIHEAP r Weatherization
Percentage of Residential customer average monthly impact-base case to 5:1 TOU
!o
(J(!o-
E
L
OJ
Eo
fU
IPC-E-18-16 Fixed Cost Report Page 83
Schedule 1
ldaho Power Company Appendix K
Schedule 7
Ba* Case
Tiered Volumetic Rate Dedgn
Sbdled Rate
TOU (5:1)
Tiers
Energy Charge
Summer Non€ummer Tiers
Energy Charge
Summer NonSummer
0-300 kwh
O\€r 300 kwh
$0.092113
$0.1 09707
$0.092113
$0.096645
On-Peak
Off-Peak
$0.250545
$0.050109
N/A
$0.050109
Summer Non€ummer Summer NonSummer
Servlce Charge $5.00 $5.00 Servlc6 Charge $18.52 $18.52
Arerage Monthly Consumption
Arerage Bill lncrease
Alerage Bill Decrease
A\erage Owrall Bill lmpact
381
$8.79 (16,708 customers)
-$1 1.78 (9,577 customers)
$1.30
Summer NonSummer
Onpeak 3-10 PM M- F
Ofrfeak Al other hours
N/A
Avg $ Change
(Monthly)
Number of
Customersi
Yoot
Cuslomers
Average
Cumulatve Bao Gas% 3iI
AYerage
Studled Cae
Ball
Average
Monthly Difr
Average
Annua! Diff
4
102
7,723
5,205
3,674
0.020h
0.39%
29.380h
19.80%
13.97%
0.l'to/o
0.39%
29.77o/o
49.57o/o
63.54o/o
$54
$29
$10
$25
$40
$81
$46
$22
$33
$42
$27
$17
$12
$8
$3
$328
$208
$ 148
$92
$31
No change 5 0.02o/o 63.56%w $44 $0 $0
g
6
o
'o
GT$O LE $5
GT$5 LE $10
GT$10 LE $15
GT$15 LE $25
GT$25 LE $100
GT $100
3,020
2,145
1,555
1 ,753
1,102
2
11.49o/.
8.16%
5.91Yo
6.67%
4.190k
0.0'lo/o
75.O5o/o
83.210/0
89.12o/o
95.790k
99.98%
99.99o/o
$53
$67
$80
$97
$129
$595
$51
$5e
$67
$78
$96
$353
-$2
-$7
-$12
-$1s
-$33
-$241
-$29
-$88
-$148
-$232
-$393
-$2,897
1 Customers with less than 12 months of data were ercluded from the bill impact analysis
30%
otr6 2oo/oP
f!Lr(uI E. ,on
doF(o:
OJ?. o%
0.,o-<- S1oo $25 to - -s2s to -s10 -s10 to 0 s0 to s10 s10 to s2s s2s to s10o > s1o0
s10o
Average Monthly Change
Percentage of Small General customer average monthly bill impact base case to TOU (5:1)
Page 84 IPC-E-18-16 Fixed Cost Report
I GT $25 LE $100
6 Gr $15 LE $25b cr$io LE $15E.9 GT $5 LE $10IGT$O LE $5
0
ldaho Power Company Appendix L
Appendix L
Schedule 95 Base Case compared to TOU Rates
Bao Case
Tlered Volumebic Rate
Studled Rab
TOU
Tlers
Energy Charge
Summer NonSummer
Energy Charge
Summer Non€ummer
0-2,(XX) I(Wh
Over 2,0fi1 kWh
s0.096640
$0.044728
s0.085930
$0.04009 1
OnPeak
MldPeak
OfrPeak
$0.040609
$0.03747 1
$0.035419
N/A
$0.027201
$0.026287
Non€ummer Summer Non€ummer
Serulce Charge
BLC > 20 kYv
Demand > 20 kW
$16.00
$1.13
$8.70
$ 16.00
$1.13
$3.97
$26.42
$1.80
$7.33
$26.42
$1.80
$6.90
Service Charge
BLC (all kW)
Demand (all kW)
Awrage Monthly Consumption
Awrage Monthly kW (1S-minute)
Awrage BLC
Awrage Bill lncrease
A\erage Bill Decrease
A\erage Bill Change
7,793
25
34
$67.66 (25,1 11 customers)
-$34.24 (5,217 customers)
$50.13
Summer Non-Summer
Onfeak 1-9 pM IvtF N/A
llidfeak 7 Al\4-1 PM & 7 AN4-1 1 PM l\ASat
9-1 1 PM Ivl-F,
7 ATA1 1 PM S-S
OffPeak All other hours
Avg 3 Ghange
(ilonthly)
Number of
Cudomersr
Average
Studied Ga-
Blll
Average
Monthly Difi
Average
Annual Diff
AverageYoot Cumulative Ba* CaseCudomors Yo Bill
s
o
osor
GT 51 00
GT $25 LE $1 00
GT $1 5 LE $25
GT $10 LE $15
GT$5LE$10
GT $O LE $5
3,846
14,027
3,237
'1,683
1,272
1,046
1,202 $
339 $
24s $
208 $
229 $
271 $
1,428
391
265
220
237
274
12.68%
46.250/.
10.67%
5.55%
4.19o/o
3.45%
12.68% $
58.93% $
69.60% $
75.15% $
79.35% $
82.80% $
2,702
629
240
148
92
30
225
52
20
12
8
3
No change 0 0.000/o 82.80% $ 215 $21s $(0) $(0)
g
o
o
'o
898
765
610
1,019
1,686
239
GT $O LE $5
GT$5LE$10
GT$1OLE$15
GT $1 5 LE $25
GT $25 LE $100
2.96%
2.52%
2.01%
3.36%
5.56%
85.76% $
88.28% $
90.29% $
93.65% $
99.21% $
296
304
304
304
519
5,696
298
311
317
323
562
(3) $
(7) $
(12) $
(20) $
(43) $
UI 00 0.79% 100.00% $ 5,992 $
Customers with less than 12 months of data were ercluded from the bill impactanalysis
e
IPC-E-18-16 Fixed Cost Report Page 85
$
$
$
$
$
$
(31)
(8e)
(1 50)
(238)
(515)
(3,544)
ldaho Power Company Appendix K
Page 86 IPC-E-18-16 Fixed Cost Report
Large General Primary Service
Seasonal Timeof-Use
Current
17C
ldaho Power Company Appendix M
Appendix M
Schedules 9P Base Case compared to Full COS
Summer Non€ummer
Service Charge
Energy Charge
On-Peak
Mid-Peak
Ofi-Peak
Demand Charge
Billing Demand
On-Peak Demand
Basic Load Gharge
$285.00 $285.00
$0.052626
0.048559
0.045900
nla
0.043545
0.042083
$
$
$
s.49 $
1.03
1.38 $
4.80
nla
1.38
Summer Non€ummer
Service Charge
Energy Gharge
On-Peak
Mid-Peak
Off-Peak
Demand Charge
Billing Demand
On-Peak Demand
Basic Load Charge
$
$
300.65 $300.65
0.040331
0.037214
0.035176
$
$
$
10.42 $
1.96
2.83 $
8.09
nla
2.83
Large General Primary Service
Seasonal Timeof-Use
Fu!! COS
IPC-E-18-16 Fixed Cost Report Page 87
nla
0.027u3
0.026425
ldaho Power Company Appendix M
ldaho Power Company
Typical Monthly Billing Comparison
State of ldaho
2017 Test Year
tPc-E-18-16
Schedule 9, Large General Service - Primary
Weighted Monthly Average
Line
No
Demand
kw
Load
Factor
Energy
kwh
(1)
Base
Rate
l2l
Studied
Rate
(3)
Difference
(2) - (1)
(4)
Percent
Difference
7.2%
1.7o/o
(2.5%)
(5.8%)
(8.5%)
I
2
3
4
5
400 50%
60%
7Oo/o
80Yo
90%
144,000
172,800
20'1,600
230,400
259,200
8,172
9,453
10,734
12,015
13,296
8,760
9,613
10,466
11,319
12,172
588
160
(268)
(6e6)
(1,124)
6
7I
9
10
s00 50o/o
60%
70o/o
800h
90%
10,144
11,745
13,347
14,948
1 6,549
10,875
11,941
13,008
14,074
15,140
731
196
(33e)
(874)
(1,408)
7.2Yo
1.70h
(2.5%)
(5.8%)
(8.5%)
11
12
13
14
15
600 50%
60Yo
70%
80%
90o/o
216,000
259,200
302,400
345,600
388,800
12,116
14,037
1 5,959
1 7,880
1 9,802
12,990
14,269
15,549
16,829
18,108
874
232
(410)
(1,052)
(1,693)
7.20h
1.7%
(2.6%)
(s.e%)
(8.6%)
16
17
18
19
20
700 5oo/o
60%
70o/o
80Yo
90o/o
252,000
302,400
352,800
403,200
453,600
14,088
16,330
18,571
20,813
23,054
15,104
16,597
I 8,090
1 9,583
21,076
1,017
268
(481)
(1,22s)
(1,e78)
7.2%
1.60/o
(2.60/")
(5.e%)
(8.6%)
21
22
23
24
25
26
27
28
29
30
800 50%
60%
70To
80%
90%
288,000
345,600
403,200
460,800
518,400
16,060
18,622
21,183
23,745
26,307
17,219
18,926
20,632
22,338
24,044
1,160
304
(552)
(1,407)
(2,263)
7.2%
1.60/o
(2.6%)
(5.e%)
(8.6%)
900 50Yo
60o/o
TOlo
8004
90o/o
324,000
388,800
453,600
518,400
583,200
18,032
20,914
23,796
26,678
29,560
19,334
21,254
23,173
25,093
27,012
1,303
340
(623)
(1,585)
(2,548)
7.2o/o
1.60/o
(2.60/,)
(5.e%)
(8.6%)
Page 88 IPC-E-18-16 Fixed Cost Report
1 80,000
21 6,000
252,000
288,000
324,000
Large Power Primary Service
Seasonal Timeof-Use
Current
(2017 COS)
ldaho Power Company Appendix M
Schedules 19P Base Case compared to Full COS
Summer Non€ummer
Service Charge
Energy Charge
On-Peak
Mid-Peak
Off-Peak
Demand Charge
Billing Demand
On-Peak Demand
Basic Load Charge
$299.00 $299.00
$0.057283
0.045551
0.040643
nla
0.042939
0.038386
$
$
$
6.60 $
1.04
1.38 $
4.89
nla
1.38
Summer Non€ummer
Service Charge $
$
48s.76 $485.76
On-Peak
Mid-Peak
Off-Peak
Demand Gharge
Billing Demand
On-Peak Demand
Basic Load Charge
0.045682
0.036326
0.032412
nla
0.028/.11
0.025399
$
$
$
12.66 $
1.96
2.65 $
9.33
nla
2.65
Large Power Primary Service
Seasonal Timeof-Use
Full Cosl-
of€ervice
IPC-E-18-16 Fixed Cost Report Page 89
ldaho Power Company Appendix M
ldaho Power Company
Typical Monthly Billing Comparison
State of ldaho
2017 Te$ Year
rPc-E-18-16
Schedule 19, Large Power Service - Primary
Weighted Monthly Average
Load
Factor
Energy
kwh
(1)
Base
Rate
(21
Studied
Rate
(3)
Difference
(2) - (1)
(4)
Percent
Difference
I
2
3
4
5
1,000 50%
600/o
71Yo
80%
90%
360,000
432,000
504,000
576,000
648,000
19,699
22,760
25,822
28,883
31,945
22,733
24,873
27,014
29,154
31,295
3,034
2,113
1,192
271
(650)
15.4%
9.3%
4.60/o
0.9%
(2.0o/")
6
7
8
I
10
2,500 50%
60%
70%
80%
900k
360,000
432,000
504,000
576,000
648,000
48,799
56,453
64,1 06
71,760
79,414
56, 1 03
6'1,455
66,806
72,158
77,509
7,305
5,002
2,700
398
(1,e05)
15.0o/o
8.9%
4.2%
0.60lo
(2.4y")
11
12
13
14
15
4,000 500a
60%
700h
80%
90o/o
360,000
432,000
504,000
576,000
648,000
77,899
90,145
102,391
114,636
126,882
89,474
98,036
1 06,598
115,161
123,723
11,575
7,892
4,208
524
(3, 160)
'l4.goh
8.8o/o
4.1%
0.5%
(2.5%)
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
5,500 50Yo
60%
70o/o
80%
90%
360,000
432,000
504,000
576,000
648,000
106,999
123,837
140,675
157,513
174,351
122,845
134,618
146,391
1 58,1 64
169,937
15,846
10,781
5,716
651
(4,4',t4)
14.8o/o
8.7o/o
4.10h
0.4o/o
(2.syo)
7,000 500h
60%
7lYo
80o/o
90%
360,000
432,000
504,000
576,000
648,000
136,098
157,529
1 78,959
200,390
221,820
156,215
171,199
'186,'183
201,167
216,151
20,117
13,670
7,224
777
(5,66e)
14.8%
8.7Yo
4.0%
0.4%
(2.60/0)
8,500 50%o
60%
70o/o
80Yo
90%
360,000
432,000
504,000
576,000
648,000
165, 't 98
191,221
217,243
243,266
269,289
1 89,586
207,781
225,975
244,170
262,364
24,388
16,560
8,732
904
(6,e24)
14.8o/o
8.7o/o
4.0o/o
0.4Yo
(2.60/")
Page 90 IPC-E-18-16 Fixed Cost Report
Line DemandNo kW
ldaho Power Company Appendix N
Appendix N
Schedules 24 Base Case compared to Basic Load Charge
ln€eaon Outof€eason
Service Charge
Energy Charge
First 164 kWh per kW
All other kWh
Demand Charge
$
$
$
22.00 $3.50
0.06814 $
0.06470
8.24 $
0.07823
0.07823
ln€eason OutofSeason
Service Charge
Energy Charge
First 164 kWh per kW
Allother kWh
Demand Charge
Badc Load Capacity
$
$
$
$
68.57 $6.97
0.04087 $
0.03880
8.44 $
8.32 $
0.07467
0.07467
lrrigation, Schedule 24
Base Case
Current Structure based on 2017
cos
lrrigation, Schedule 24
Addition of Basic Load Gharge Badc Load Charge
IPC-E-18-16 Fixed Cost Report Page 91
ldaho Power Company Appendix N
Li ne
No
t
2
3
4
5
6
7
8
9
10
11
t2
L3
14
15
t6
77
18
19
20
2t
22
23
24
25
26
27
28
29
30
ldaho Power Company
Tlpical Monthly Billing Comparison
State of ldaho
2017 Test Year
rPc-E-18-16
Schedule 24, Fgrlcultural lrrigation Service - Secondary
ln-Season
(1) (2)
Demand Load Energy Base Studied
kW Factor kwh Rate Rate
10 20% L,44O 5202.52 5294.99
35% 2,520 5273.09 5337.31
so% 3,600 s342.96 5379.22
65% 4,680 s4t2.U 5421.12
80% 5,760 5482.7L 5463.03
50 20% 7,2N 5992.73 51,247.56
35% 12,600 51,277.41 51,412.28
50% 18,000 5L,626.79 51,621.80
65% 23,400 5t,9t6.tl 51,831.32
80% 28,800 s2,325.55 $2,040.84
100 20% L4,4OO 51,963.46 52,414.55
35% 25,200 52,532.82 52,755.99
50% 36,000 s3,231.58 s3,175.03
65% 46,800 s3,930.34 s3,59+.02
80% 57,600 54,629.t0 54,013.11
300 20% 43,2OO s5,846.39 s7,106.50
35% 75,600 57,554.47 58,130.82
50% 108,000 s9,650.76 s9,387.95
65% 74O,4OO 511,747.04 510,645.07
80% r72,8OO s13,843.32 s11,902.19
5oo 20% 72,000 59,129.30 511,798.45
35% 126,000 5!2,576.!0 513,505.65
SU/o 1,80,000 s16,069.91 s15,600.86
65% 234,000 519,563.72 517,696.05
8tr/o 288,000 s23,O57.52 519,79t.27
750 20% L08,000 514,582.96 517,663.38
35% 189,000 s18,853.17 $20,224.19
5U/o 27O,N0 s24,093.88 s23,355.99
65% 351,000 s29,334.59 s25,509.80
80% 432,000 s34,575.29 s29,652.6L
ln-season months include June, July, AuBust, September
(3)
Difference
(2) - (1)
se2.48
564.22
s36.26
Sg.za
-Srg.se
szas.sg
5134.87
-s4.ss
-sraa.ss
-528/,.7t
s4s1.09
s223.77
-ss6.ss
-5336.27
-561s.9e
S1,260.11
ss76.3s
-Szoz.sr
-S1,101.97
-S1,941.13
52,069.t4
se2e.s4
-s+09.00
-5L,867.67
-53,2aa.2a
3,080.42
L,371.O2
(726.8el,
(2,824.79)
(4,922.68)
(4)
Percent
Difference
45.66%
23.s2%
10.57%
2.07%
-4.08%
2s.07%
70.56%
-o.3L%
-7.33%
-12.24%
22.97%
8.87%
-1,.75%
-8.s6%
-L3.31%
21.55%
7.63%
-2.72%
-9.38%
-74.02%
21.27%
7.39%
-2.92%
-9.55%
-14.L7%
2t.t2%
7.27%
-3.02%
-9.63%
-14.24%
Page 92 IPC-E-18-16 Fixed Cost Report
ldaho Power Company Appendix N
ldaho Power Gompany
Tlpical Monthly Billing Gorparison
State of ldaho
tPc-E-18-16
2017 Test Year
Schedule 24, Aqricultural lrrigation Service - Secondary
Out-of-Season
Line Demand
No kW
110
2
3
4
5
650
7
8
9
10
7L 100
L2
13
!4
15
16 300
t7
18
19
20
2t 500
22
23
24
25
26 750
27
28
29
30
Energy
kwh
1,440
2,520
3,600
4,680
5,760
7,2W
12,600
18,000
23,400
28,800
14,400
25,200
35,000
46,800
57,600
43,200
75,600
L08,000
140,4@
T72,8N
72,N0
126,000
190,000
234,O@
288,000
108,000
189,000
270,N0
351,000
432,OO0
(1)
Base
Rate
s116.1s
szoo.0+
s28s.13
SEog,sz
s4s4.11
ss66.76
s989.20
S1,411.65
s1,834.09
52,256.53
S1,130.02
51,974.90
52,8t9.79
53,664.68
s4,509.57
53,383,05
55,9tl.lt
58,452.37
510,987.03
513,s2L.70
55,636.08
59,860.52
s14,084.95
S18,309.39
S22,533.83
59,4s2.37
S14,789.03
52r,r25.68
527,462.33
S33,798.99
(2)
Studied
Rate
s114.s0
s19s.1s
527s.7e
Ssss.44
s437.09
Ssa+.or
5947.84
S1,351.07
S1,754.30
$2,t57.53
s1,082.25
S1,888.71
$2,695.17
53,50t.6+
s4,308.10
53,232.87
55,o5z.zo
s8,071.58
S10,490.96
s12,910.34
55,383.38
s9,415.58
513,M7.98
$17,480.28
521,512.58
58,071.58
5t4,tzo.o3
S20,168.48
526,2L6.93
S32,265.38
(3)
Difference
2-1
(1.6s)
(s.4e)
(e.34)
( 13.18)
(17.02)
(22.14)
(41.35)
(60.s7)
(7e.78)
(se.oo)
(47.76)
(86.1e)
(L24.62)
(163.04)
(20L.47l,
(1s0.23)
(26s.s1)
(380.80)
(4s6.08)
(611.36)
(2s2.71)
(444.84)
(636.s8)
(82s.11)
(L,O2r.24)
(380.80)
(65e.oo)
(ss7.2o)
(1,245.40)
(1,533.50)
(4)
Pe rce nt
Diffe re nce
-1.42%
-2.74%
-3.27%
-3.57%
-3.75%
-3.91%
-4.L8%
-4.29%
-4.35%
-4.39%
-4.23%
-4.36%
-4.42%
-4.4s%
-4.47%
-4.M%
-4.49%
-4.51%
-4.52%
-4.52%
-4.48%
-4.51%
-4.52%
-4.53%
-4.53%
-4.57%
-4.52%
-4.s3%
-4.53%
-4.s4%
Load
Factor
20%
35%
s0%
55%
80%
20%
35%
so%
6s%
8tr/o
2tr/o
35%
so%
65%
80%
20%
35%
50%
6s%
80%
20%
3s%
5tr/o
6s%
80%
20%
35%
Str/o
65%
80%
IPC-E-18-16 Fixed Cost Report Page 93
ldaho Power Company Appendix N
Line Demand
No kW
110
2
3
4
5
550
7
8
9
10
tL 100
t2
13
74
15
16 300
t7
L8
19
20
2L 500
22
23
24
25
26 750
27
28
29
30
ldaho Power Corpany
Tlpical Monthly Billing Gonparison
State of ldaho
rPc-E-18-16
2017 Test Year
Schedule 24, Agricultural lrrigation Service - Secondary
Weighted Average Monthly
(1) (2)
Energy Base Studied
kwh Rate Rate
1,40 L44.94 L74.67
2,520 224.79 242.53
3,600 3U.4L 310.27
4680 384.03 378.00
5,760 463.il M5.73
7,200 708.75 776.93
72,600 1,085.27 t,t02.66
18,000 1,483.36 L,ML.32
23,400 1,881.45 L,779.98
28,800 2,279.54 2,LLg.il
14,40 1,407.83 1,526.35
25,200 2,160.88 2,L77.80
36,000 2,957.05 2,855.73
45,800 3,753.23 3,532.45
57,600 4,549.4! 4,209.77
43,200 4,204.76 4,524.M
75,600 6,463.30 6,478.40
108,000 8,851.83 8,510.37
140,400 11,240.37 Lo,542.33
172,800 13,628.90 L2,574.29
72,0@ 7,OOO.49 7,521'73
126,000 L0,765.7L 70,779.00
180,000 L4,746.6L 14,1_65.50
234,WO L8,727.50 t7,552.21
288,000 22,708.39 20,938.81
108,000 10,495.90 11,268.85
189,000 16,L43.74 L6,L54.75
270,000 22,LL5.O8 2L,234.65
351,000 28,086.42 26,314.56
432,000 34,057.76 37,394.46
Load
Factor
2tr/o
35%
5tr/o
6s%
80%
20%
35%
Str/o
65%
8U/o
20%
35%
50%
65%
80%
20%
3s%
50%
6s%
80%
20%
3s%
Str/o
65%
80%
20%
35%
50%
65%
8tr/o
(3)
Difference
(2) - (1)
29.73
77.74
s.85
(6.03)
(17.e1)
58.18
77.38
(42.04)
(LO7.47)
(150.e0)
L18.52
16.93
(101.s3)
(220.7e)
(33s.64)
319.88
15.11
(341.47)
(5e8.04)
(1,054.61)
527.24
L3.29
(s81.00)
(1,175.30)
(1,759.58)
772.94
11.01
(880.43)
(7,777.86',)
(2,663.291
(4)
Pe rce nt
Difference
20.57%
7.89%
t.93%
-1.57%
-3.86%
9.62%
t.60%
-2.83%
-5.39%
-7.06%
8.42%
o.78%
-3.45%
-s.88%
-7.47%
7.6L%
o.23%
-3.86%
-6.21%
-7.74%
7.45%
o.L2%
-3.94%
-6.28%
-7.79%
7.36%
0.07%
-3.98%
-6.31%
-7.82%
Page 94 IPC-E-18-16 Fixed Cost Report