20230601Direct Aschenbrenner .pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES AND CHARGES FOR ELECTRIC SERVICE IN THE STATE OF IDAHO AND FOR
ASSOCIATED REGULATORY ACCOUNTING TREATMENT.
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CASE NO. IPC-E-23-11

IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
CONNIE G. ASCHENBRENNER
ASCHENBRENNER, DI 2
Idaho Power Company
Q. Please state your name, business address, and 1
present position with Idaho Power Company (“Idaho Power” or 2
“Company”). 3
A. My name is Connie G. Aschenbrenner. My 4
business address is 1221 West Idaho Street, Boise, Idaho 5
83702. I am employed by Idaho Power as the Rate Design 6
Senior Manager in the Regulatory Affairs Department. 7
Q. Please describe your educational background. 8
A. In May of 2006, I received a Bachelor of 9
Business Administration degree in Finance from Boise State 10
University in Boise, Idaho. In December of 2011, I earned a 11
Master of Business Administration degree from Boise State 12
University. In addition, I have attended the electric 13
utility ratemaking course The Basics: Practical Regulatory 14
Training for the Electric Industry, a course offered 15
through New Mexico State University’s Center for Public 16
Utilities. 17
Q. Please describe your work experience with 18
Idaho Power. 19
A. In 2012, I was hired as a Regulatory Analyst 20
in the Company’s Regulatory Affairs Department. My primary 21
responsibilities included support of the Company’s 22
Commercial and Industrial customer class’s rate design and 23
general support of tariff rules and regulations. In my time 24
as a Regulatory Analyst, I also provided support for 25
ASCHENBRENNER, DI 3
Idaho Power Company
Residential and Small General Service rate design, as well 1
as regulatory support associated with demand-side 2
management (“DSM”) activities. In 2017, I was promoted to 3
Rate Design Manager for Idaho Power, and in 2019 I was 4
promoted to my current role as Rate Design Senior Manager. 5
I am currently responsible for the management of the rate 6
design strategies of the Company, as well as oversight of 7
all tariff administration. In my current role, I am also 8
one of the Company representatives at its Energy Efficiency 9
Advisory Group (“EEAG”) meetings. 10
Q. What is the purpose of your testimony in this 11
matter? 12
A. In my testimony, I will describe generally how 13
customer rates are developed and the Company’s approach to 14
rate design strategy as well as the policy basis for the 15
rate design proposals being made in this case. I will also 16
describe the overall objectives I provided to the 17
Regulatory Consultants and Analysts for the development of 18
the Company’s proposed rate designs and general tariff 19
updates. I will also present an overview of the Company’s 20
approach to developing pricing for its on-site generation 21
customers, specifically considering interdependencies 22
between this case and Case No. IPC-E-23-14, which is 23
currently pending before the Idaho Public Utilities 24
Commission (“Commission”). Finally, I will describe the 25
ASCHENBRENNER, DI 4
Idaho Power Company
approach the Company took to updating its tariff schedules 1
and rules to ensure the language in the tariff reflects 2
current business practices. 3
Q. Please provide a witness overview for the 4
Company’s CCOS, rate design, and general tariff revision 5
proposals. 6
A. Company Witness Mr. Paul Goralski will present 7
the Company’s recommendation as it relates to class cost-8
of-service (“CCOS”) in this case and will also present rate 9
design recommendations for the Company’s existing Special 10
Contract customers (Micron, Simplot – Pocatello, and INL) 11
as well as pending and prospective Special Contract 12
customers (Brisbie, Lamb Weston, and Simplot – Caldwell). 13
Mr. Goralski will also present the rate design proposal for 14
Schedule 20, Speculative High-Density Load as well as the 15
proposed Fixed Cost Adjustment rates and the corresponding 16
modifications to Schedule 54. 17
Company Witness Mr. Grant Anderson will explain the 18
proposed rate design and resulting prices for the 19
residential classes, including standard service (Schedule 20
1), time-of-use (“TOU”) (Schedule 5), and residential on-21
site generation (Schedule 6) and will explain the Company’s 22
Residential Price Modernization Plan. Mr. Anderson will 23
also present the rate design proposals for Small General 24
Service On-Site Generation (Schedule 8), Large General 25
ASCHENBRENNER, DI 5
Idaho Power Company
Service – Primary and Transmission (Schedule 9P/T) and 1
Large Power customers (Schedule 19). 2
Company Witness Mr. Zack Thompson will present the 3
rate design proposals for Small General Service (Schedule 4
7), Large General Service – Secondary (Schedule 9S), 5
Agricultural Irrigation Service (Schedule 24), Dusk to Dawn 6
Customer Lighting (Schedule 15), Street Lighting Service 7
(Schedule 41), Traffic Control Signal Lighting Service 8
(Schedule 42), and Non-Metered General Service (Schedule 9
40). 10
Finally, Company Witness Mr. Riley Maloney will 11
present the recommendation for the Company’s Standby 12
Service schedules (Schedules 31 and 45) and Alternate 13
Distribution Service schedule (Schedule 46). Mr. Maloney 14
will also present several proposed modifications to the 15
Company’s tariff. 16
I. RATE DESIGN OVERVIEW AND OBJECTIVES 17
Q. How are customer rates developed? 18
A. After the Idaho jurisdictional revenue 19
requirement is determined, the Company develops a class 20
cost-of-service study (“CCOS Study”) whereby it allocates 21
the revenue requirement to each customer class based on 22
their specific utilization of the system. The methodology 23
for separating costs among classes consists of a three-step 24
process generally referred to as classification, 25
ASCHENBRENNER, DI 6
Idaho Power Company
functionalization, and allocation. In all three steps, 1
recognition is given to the way in which the costs are 2
incurred by relating these costs to the way in which the 3
utility is operated to provide electrical service. Once 4
individual costs have been allocated to the various classes 5
of service, it is possible to total these costs as 6
allocated and arrive at a breakdown of functionalized and 7
classified unit costs which can be relied on to inform rate 8
design. 9
Q. Please describe the objectives underlying the 10
Company’s rate design strategy. 11
A. The Company’s primary rate design objective is 12
to establish rate structures and prices that will recover 13
the revenue requirement targets for each customer class. 14
Additionally, the Company seeks to design rates that assign 15
costs to those customers that cause the Company to incur 16
the costs, a principle known as “cost causation,” and to 17
incorporate price signals to encourage wise and efficient 18
use of energy. 19
Q. How can rate design influence customer 20
behavior? 21
A. The rate design itself – or structure – and 22
the prices set by these designs can impact the amount of 23
electricity customers consume and either encourage or 24
discourage usage at certain times. The Company believes 25
ASCHENBRENNER, DI 7
Idaho Power Company
that rates should be designed in a manner such that changes 1
in a customer’s consumption (both the timing or quantity of 2
usage) will result in decreases or increases to the 3
customer’s bill that track with overall decreases or 4
increases in costs incurred by the utility to provide 5
service. 6
Q. How effective are the Company’s current rate 7
structures in achieving its rate design objectives? 8
A. Current rate structures fall short of 9
achieving the Company’s long-term objectives in a number of 10
key areas. A large portion of the fixed costs to serve 11
customers is collected through volumetric energy charges. 12
In other words, the rate structure does not align well with 13
how costs are incurred, and as a result, the price signals 14
sent to these customers are inconsistent with the nature of 15
the costs of providing electricity. Further, the rates 16
offer little incentive for customers to use electricity 17
cost-effectively. 18
Q. Why does the Company believe it is important 19
to align prices with the underlying cost structure? 20
A. Customers respond to price signals. If the 21
Company’s rate structures are not aligned with the 22
underlying cost drivers, customers do not have access to 23
information that will allow them to make decisions based on 24
the economics from their perspective or for the broader 25
ASCHENBRENNER, DI 8
Idaho Power Company
utility system. This dynamic is increasingly important to 1
Idaho Power’s system. Over the last several years, 2
advancements in technology have influenced customer 3
adoption of several behind-the-meter energy solutions, 4
including energy efficiency, smart appliances, on-site 5
generation, and energy storage systems. The Company 6
believes that structuring rates in a manner that will more 7
equitably collect fixed costs, while also sending price 8
signals to promote efficiencies, is important to the long-9
term management of system costs. 10
In addition to sending the right price signal to 11
influence behavior, cost-informed rates help to limit cross 12
subsidies within a given class. 13
Q. Are there any other policy objectives to 14
consider regarding rate design? 15
A. Yes. There are several other important 16
ratemaking objectives the Commission has historically 17
relied upon when ultimately establishing rates. These 18
include evaluating customers’ ability to pay, 19
understandability of the rate structure and rates 20
themselves, and to what extent the rates provide some 21
stability for customers. While the Company believes each of 22
these objectives is important and should factor into an 23
ultimate decision, it also believes that the best starting 24
point for Commission deliberations is an economic one. 25
ASCHENBRENNER, DI 9
Idaho Power Company
II. RATE DESIGN RECOMMENDATIONS 1
Q. Has the Company identified opportunities for 2
improving the current rate design applicable to its major 3
customer classes? 4
A. Yes. Generally, the Company is proposing to 5
adjust each of the billing components within its existing 6
structures to move incrementally closer to their cost-of-7
service, while targeting collection of the revenue assigned 8
to each class. Accordingly, I have directed each of the 9
Company witnesses who have prepared rate design 10
recommendations to prioritize movements in collection 11
towards cost-of-service, which includes moving away from 12
tiered rate designs and shifting fixed cost collection into 13
the appropriate charges, while balancing the magnitude of 14
those changes with the resulting customer impacts. Table 1 15
shows a summary of the requested rate design changes for 16
the Company’s existing service schedules and identifies the 17
Company witness who developed the proposed rates. 18
//19
ASCHENBRENNER, DI 10
Idaho Power Company
Table 1 1
Summary of Existing Rate Designs & Proposed Modifications 2 Current
Structure Proposed Modifications Witness
Residential
(Schedules 1 & 6) •Service Charge
• 3 Inclining Block Tiers
•
collection through the
Service Charge
• Flatten the tiers
Anderson
Residential Time-
of-Use (“TOU”)
(Schedule 5)
•Service Charge
• Summer On & Off-Peak
• Non-Summer Mid & Off-
Peak
•
align with IRP-informed
hours of highest risk
• Introduce larger
Small Commercial
(Schedules 7 & 8) •Service Charge
• 2 Inclining Block Tiers
•
collection through the
Service Charge and flatten
Anderson
Large Commercial
Secondary
(Schedule 9S)
•Service Charge
• Two-Block Demand/BLC
• 2 Declining Block Tiers
•
collection through the
Service Charge
• Replace Two-Block
Demand/BLC and
Declining Tiers with a
seasonal, flat rate
• Introduce an optional TOU

Irrigation (Schedule 24) •Service Charge
• In-Season Demand
• Load-Factor Pricing
•
collection through the
Service Charge
• Replace Load-Factor
Pricing with a flat energy

Large Commercial
Primary &
Transmission (Schedules 9P/T)
•Service Charge
• Demand, BLC, and On-
Peak Demand
• TOU Energy Rates
•
elements with underlying
cost drivers as informed by
CCOS

Large Power
(Schedule 19)
•Service Charge
• Demand, BLC, and On-
Peak Demand
• TOU Energy Rates
Better align existing
elements with underlying
cost drivers as informed by
CCOS

Special Contracts
(Schedules 26, 29,
30, & 32)
•Varied •Better align existing
elements with underlying
cost drivers as informed by

ASCHENBRENNER, DI 11
Idaho Power Company
Q. Please describe the Company’s general 1
goals/strategies for addressing the weaknesses in existing 2
rate designs in this case. 3
A. In this case, the Company intends to establish 4
rate structures that are more in line with cost causation, 5
while balancing customer understandability and bill impact. 6
Overall, the Company is seeking to implement changes that 7
will take a step towards correcting a long-standing 8
inequity within the residential class by implementing a 9
plan to establish better price signals within that class. 10
Further, the Company’s proposal will continue to better 11
align the commercial and irrigation rate designs with cost-12
causation, providing for more economic price signals to 13
those customer classes. 14
A. Eliminate Tiered Rate Design 15
Q. What rate classes currently rely on some form 16
of tiered rates? 17
A. Schedules 1, 6, 7, 8, 9S and 24 all rely on a 18
form of tiered rates. Currently, Idaho Power’s tiered rates 19
include inclining block rates, whereby the prices 20
associated with each defined block of energy usage is 21
higher than the proceeding block, and declining block 22
rates, whereby the prices associated with each block of 23
energy usage is lower than the proceeding block. 24
ASCHENBRENNER, DI 12
Idaho Power Company
Inclining Block Rates 1
Q. What rate classes currently have an inclining-2
block tiered rate design? 3
A. Schedules 1, 6, 7, and 8. Schedules 1 and 6 4
rely on a three-tiered inclining block structure while 5
Schedules 7 and 8 rely on a two-tiered inclining block 6
structure. 7
Q. What is the purpose of an inclining-block 8
rate? 9
A. A primary goal of an inclining tiered 10
structure is to encourage conservation by charging a higher 11
rate as energy consumption increases over a billing period. 12
Once a threshold of energy consumption is exceeded within a 13
billing period, the rate becomes higher to send a price 14
signal intended to encourage efficiency and/or 15
conservation. Historically, the inclining block rate 16
structure has been used as a tool for encouraging customers 17
to use less energy. The theory underlying this concept is 18
that the first block covers some basic level of usage at a 19
lower rate to help keep the overall bill affordable for 20
customers and sequential blocks with higher rates make 21
incremental energy usage more expensive to encourage energy 22
efficiency. 23
Q. Are there downsides to this type of a rate 24
design? 25
ASCHENBRENNER, DI 13
Idaho Power Company
A. Yes. The tiered rate structure has potential 1
to unfavorably impact bills of customers who reside in 2
older, less efficient homes, or those homes with all-3
electric heat. These customers may be unable to safely 4
reduce their energy beyond a certain threshold or may not 5
be able to efficiently reduce their energy usage in 6
response to the established price signals. The most 7
significant downside is that the tiered rate structure does 8
not reflect how costs are incurred throughout the billing 9
period and therefore does not send a price signal related 10
to the differing costs to produce or procure energy 11
throughout the billing period. 12
Proponents of inclining block rates believe they 13
provide customers with greater control over their electric 14
charges. However, it is important to note that high-end 15
energy use is often electric heating and cooling, and while 16
customers can elect to turn off or lower their heating 17
requirements to lower their bill, this could compromise 18
basic health and safety. The Company does not believe an 19
inclining block structure is the right way to promote 20
energy efficiency for residential customers over the long-21
term, and, as explained more fully below, proposes to 22
transition to a rate design that will better enable 23
efficiencies on its system. 24
ASCHENBRENNER, DI 14
Idaho Power Company
In short, tiered rates are not cost-based and serve 1
to penalize higher usage customers. 2
Q. Why are tiered rates not cost-based? 3
A. There is no cost-based reason why after using 4
800 kilowatt hours (“kWh”) or 2,000 kWh in a billing period 5
the next kWh consumed by a customer should cost more. 6
Conversely, the timing of energy consumption, both 7
seasonally and during different hours, can affect the 8
utility’s cost of providing service to the customer. The 9
load factor or the effective utilization of kWh consumption 10
relative to peak kilowatt (“kW”) demand can also change the 11
average cost of providing energy. However, additional 12
overall usage in a customer’s billing period does not make 13
it incrementally more expensive for the utility to produce 14
the next kWh of electricity when both fixed and variable 15
costs are considered. 16
Q. Why do tiered rates unduly penalize customers? 17
A. Charging higher prices for greater usage in 18
each billing period generally causes large users to 19
subsidize smaller users. Under a tiered rate structure, 20
customers who heat their homes with natural gas benefit and 21
those who use electric heat are penalized. A household with 22
several people living under one roof will be more likely to 23
have usage in the higher second and third block rate than a 24
person living alone. Effectively, inclining block rates 25
ASCHENBRENNER, DI 15
Idaho Power Company
unfairly reward some customers and penalize others, often 1
for reasons outside the customer’s control. For those 2
reasons, the Company is proposing to eliminate this type of 3
rate structure for its residential customers over time. 4
Q. Are there any other reasons why the Company 5
believes that eliminating tiers from Schedule 1 is 6
advantageous? 7
A. Yes. Eliminating tiers for Schedule 1 makes 8
the comparison to Schedule 5, which does not have tiers, 9
easier for customers to assess regarding the potential 10
benefits of time-variant pricing. 11
Additionally, moving away from an inclining block 12
tiered structure to a seasonally flat structure would 13
better position residential customers for future pricing 14
structure changes. For example, a change from a seasonal 15
flat rate to an introductory or mandatory TOU rate would 16
cause less customer confusion – whereas a change from the 17
existing inclining block structure to TOU rates may be more 18
volatile and cause a varying degree of bill impacts to 19
individual customers. 20
Declining Block Rates 21
Q. What rate classes currently have a declining -22
block tiered rate design? 23
A. Schedules 9S and 24. 24
ASCHENBRENNER, DI 16
Idaho Power Company
Q. Please describe the details of the declining 1
block tiered rate that applies to Schedule 9S. 2
A. The Schedule 9S rate design includes a two-3
tier declining block energy charge and a two-block demand 4
and basic load capacity (“BLC”) charge. In this rate 5
design, the first block of kWh consumption is billed at a 6
higher rate than all other consumption. 7
Q. Is the Company proposing changes to the 8
Schedule 9S rate design? 9
A. Yes. Under the Schedule 9S rate design, the 10
higher first block energy charge is intended to collect 11
costs that are classified as demand and would otherwise be 12
collected through a demand charge. As described by Mr. 13
Thompson in this case, the Company is proposing to “unwind” 14
the declining block Schedule 9S rate design and replace it 15
with a rate structure more in line with other large general 16
service customers, containing a billing demand and BLC 17
applied to all kW and seasonal energy charges. 18
Q. Please explain the considerations in 19
evaluating the change to Schedule 9S. 20
A. The Schedule 9S rate design was initially 21
implemented in the 2005 general rate case1 primarily to ease 22
impacts on customer bills as a customer’s usage made them 23

1 In the Matter of the Application of Idaho Power Company for Authority to Increase its Base Rates and Charges for Electric Service in the
State of Idaho, Case No. IPC-E-05-28, Order No. 30035 (May 12, 2006).
ASCHENBRENNER, DI 17
Idaho Power Company
ineligible for Schedule 7 service and where they instead 1
qualified for service under Schedule 9S. At that time, 2
customers were experiencing a “pain point” when they 3
transitioned back and forth between Schedule 7 and Schedule 4
9 due to the differences in the rate designs. Several 5
changes were made to the address that pain point, including 6
modifying the eligibility criteria so that once a customer 7
qualifies for Schedule 9 service, they will continue to 8
take service under that schedule. At the time, the Company 9
signaled that combining the Schedule 7 and Schedule 9S 10
class may be most appropriate in the long term. 11
Q. Did the Company consider providing additional 12
customer options to help improve understandability or 13
provide a price signal to promote system efficiency? 14
A. Yes. As more fully described below, the 15
Company is proposing to implement an optional TOU rate 16
structure where time-differentiated volumetric energy rates 17
would give a better price signal to prioritize the more 18
critical times when customers could shift load. It costs 19
more to serve load during summer and non-summer peak times 20
and an on-peak summer rate encourages more efficient use of 21
the system as well as fairly charging customers based on 22
their load profiles. 23
Q. Is the Company proposing to combine the small 24
and large general secondary rate classes in this case? 25
ASCHENBRENNER, DI 18
Idaho Power Company
A. No. In this case, the Company is proposing to 1
slightly modify the Schedule 7 design, as more fully 2
described in the Direct Testimony of Mr. Thompson, to 3
collect more fixed costs through the Service Charge and 4
commensurately reduce the reliance on volumetric rates for 5
fixed cost collection. The Schedule 7 class has a 6
disproportionate number of small users (nearly 60 percent 7
of the class uses less than 300 kWh per month), and the 8
Company determined that, at this point, it would not 9
propose combining the classes. 10
However, in evaluating its proposed rates, the 11
Company did consider how Schedule 7 customers transitioning 12
onto Schedule 9 would be impacted, which in part influenced 13
the proposed level of collection through the Service Charge 14
for both Schedules 7 and 9S. 15
Q. What rate design currently applies to Schedule 16
24? 17
A. Schedule 24 relies on “load factor pricing” 18
which is like a declining block, where the price of the 19
first tier is higher than that of the second tier. The 20
first block charges irrigation customers a monthly rate per 21
kWh for the first 164 kWh per kW of demand, where the 22
second block charges customers a lower monthly energy rate 23
per kWh of all other energy use. 24
Q. Is this rate design cost based? 25
ASCHENBRENNER, DI 19
Idaho Power Company
A. No. Like the Schedule 9S rate design, this 1
rate design collects costs otherwise classified as demand 2
through the first block; however, unlike the Schedule 9S 3
design, customers are charged for all units of billing 4
demand during the in-season time period. The Company has 5
found this rate design tends to be complex to explain to 6
customers. As a result, and as described in the Direct 7
Testimony of Mr. Thompson, the Company is proposing to move 8
the demand-classified costs out of the first tier and 9
collect those costs through the demand charge, which the 10
Company believes would be a more straightforward rate 11
design for Schedule 24 customers to understand. 12
B. Expanded Summer Season & TOU Rates 13
Q. Do the Company’s current rate structures 14
reflect the time-variant nature of electricity? 15
A. Only to an extent. The rate designs applicable 16
to most of the Company’s service schedules include a 17
seasonal component. Additionally, the large users, 18
Schedules 9 P/T and 19, have mandatory time-differentiated 19
energy charges. 20
Q. What is the Company’s view on seasonal rates? 21
A. The cost to provide service to customers 22
varies throughout different times of the year. For Idaho 23
Power’s system, it is generally more expensive to meet 24
customer energy requirements in the summer and seasonal 25
ASCHENBRENNER, DI 20
Idaho Power Company
rates are an effective tool to promote reduced consumption 1
during those higher cost months. Acknowledging this, the 2
Company implemented seasonal rates for Schedules 1, 7, 9, 3
and 19 in its 2003 General Rate Case (“GRC”). Since that 4
time, the summer season for purposes of ratemaking has 5
remained unchanged – that is, for most customers, the 6
summer season is defined as June 1 through August 31. 7
Q. What is the Company’s proposed summer season 8
in this case and how did it develop that recommendation? 9
A. The Company is proposing to expand the summer 10
season by one month to include September. Over the last 11
several years, the Company’s Integrated Resource Plan 12
(“IRP”) has identified high-risk hours are more frequently 13
occurring later in the summer, often showing up in 14
September. Shifting to a four-month summer season better 15
aligns with current and future high-risk hours. 16
Q. What is the Company’s view on TOU rates? 17
A. TOU rates can be an effective way to send a 18
price signal to customers to encourage them to shift energy 19
usage to specific hours in the day that are less costly to 20
serve. This price signal can be effective to promote energy 21
efficiency and system efficiency rather than strictly a 22
conservation signal, as the tiered rates do. As more fully 23
described by Mr. Anderson and Mr. Thompson, the Company is 24
proposing to expand its TOU offerings for both residential 25
ASCHENBRENNER, DI 21
Idaho Power Company
and commercial customers and to establish a basis for 1
potential opt-out or mandatory TOU rates for those classes. 2
Residential TOU 3 4 Q. Is the Company proposing to expand its TOU 5
offering for residential customers as part of this GRC? 6
A. Yes. The Company has had an optional TOU 7
offering in place for its residential customers since 2005; 8
however, only a small number of customers (currently less 9
than 1,000) opt to take that service from Idaho Power. The 10
Company is proposing to redesign its optional residential 11
TOU offering in a few ways: (1) modify and shorten the on-12
peak windows to align with the Company’s highest risk hours 13
as informed by the 2023 IRP and (2) introduce a larger 14
differential between on- and off-peak times. 15
Q. Please generally describe how the TOU offering 16
was designed. 17
A. First, the Company relied on the analysis 18
performed by the power supply planning team in preparation 19
of the 2023 IRP to determine which hours are currently 20
considered highest risk. These hours were used to inform 21
the summer and non-summer on- and off-peak price periods 22
utilized in the Schedule 5 rate design. I then directed Mr. 23
Anderson to rely on the results of that analysis to inform 24
his rate proposal. 25
ASCHENBRENNER, DI 22
Idaho Power Company
Q. How is the Company proposing to set the 1
differentials between on-, mid-, and off-peak? 2
A. The Company’s approach varied slightly by 3
customer class. For Schedule 5 customers, I directed Mr. 4
Anderson to develop the offering in a manner that would be 5
most effective at promoting a response to the price signal. 6
Q. Please describe how system efficiencies may be 7
gained under this type of a rate structure. 8
A. TOU pricing (including Critical Peak Pricing) 9
was identified as having the potential to manage customer 10
demand in a recently completed Demand Response Potential 11
Study, which will be relied on in the 2023 IRP. For the 12
residential class, the total potential from TOU pricing 13
programs amounted to approximately 8 MW. To the extent 14
customers respond to this type of a rate design, the 15
Company may be able to delay building traditional supply-16
side resources. 17
Q. Did the Company consider making TOU a default 18
or mandatory rate offering for residential customers? 19
A. Yes, however, while the Company believes TOU 20
is a more efficient and effective way to send energy and 21
system efficiency price signals, it is aware that a change 22
in a single year — from the current tiered rate structure 23
to a mandatory or even a default TOU program — would be a 24
significant impact to many of its residential customers 25
ASCHENBRENNER, DI 23
Idaho Power Company
that may be unfamiliar with this type of rate design, or 1
who are otherwise unable to respond to the price signal. 2
Based on these considerations, in this case, the 3
Company is proposing a three-year transition whereby it 4
will gradually increase the Service Charge while 5
eliminating the inclining block tier rates, which, at the 6
end of the transition period, will better position the 7
Company to consider proposing mandatory or default TOU for 8
all customers in the future. This will also provide the 9
Company an opportunity to evaluate the impacts and 10
effectiveness of the on-peak to off-peak price ratio of 11
4.0x proposed in this case. 12
Commercial and Industrial TOU 13
14 Q. Is the Company proposing to modify or expand 15
TOU for its commercial and industrial customers? 16
A. Yes. Schedules 19 and 9P/T already have TOU 17
rates in place. The Company is aware that many of its 18
Schedule 9S customers would like to take service under a 19
time-differentiated rate design as this type of a design 20
will better enable customers with discretionary load to 21
manage their energy bills. 22
Q. Why is the Company proposing only an optional 23
TOU service offering for Schedule 9S customers as opposed 24
to making it a mandatory service? 25
ASCHENBRENNER, DI 24
Idaho Power Company
A. The Company is proposing the optional Schedule 1
9S TOU offering at this time to incentivize customers, who 2
have the ability, to shift load to off-peak periods by 3
sending cost-based price signals informed by the Company’s 4
high-risk hours identified in preparation of the 2023 IRP. 5
This encourages customers to use the system more 6
efficiently and economically based on both how the Company 7
incurs cost and the high-risk time periods. 8
For example, if a customer with electric vehicle 9
charging stations selected the TOU offering, they would be 10
encouraged to charge their vehicles during off-peak hours. 11
This would lessen the burden on the system during on-peak 12
time periods as well as save the customer money compared to 13
if they were on the standard service offering. 14
Q. How is the Company proposing to set the 15
differentials between on- and off-peak? 16
A. I directed both Mr. Anderson and Mr. Thompson 17
to develop a proposal to isolate both the variable and 18
fixed cost components of the volumetric charge and only 19
apply a differential to the energy classified portion of 20
the rate. By developing the rates this way and having the 21
fixed cost component of the volumetric rate remain constant 22
for all kWh within a given season, the principles of cost-23
causation are maintained. That is, when a customer shifts 24
ASCHENBRENNER, DI 25
Idaho Power Company
usage to another time period, the underlying costs are 1
expected to increase or decrease commensurately. 2
C. Residential Price Modernization Plan 3
Q. Please explain the Company’s Residential Price 4
Modernization Plan. 5
A. As more fully described in the Direct 6
Testimony of Mr. Anderson, the Company is proposing a 7
three-year transition period to modify the structure of its 8
residential rates whereby it will increase the Service 9
Charge and lower the energy charges commensurately over 10
that period. 11
Q. Why is Idaho Power requesting to implement the 12
Residential Price Modernization Plan? 13
A. The current residential rate structure does 14
not align with Idaho Power’s embedded cost structure. 15
Providing electric service requires a significant amount of 16
capital infrastructure, which is largely a fixed cost once 17
infrastructure goes into service. The current residential 18
rate structure is comprised of the Service Charge, which is 19
a monthly fixed charge, and Energy Charges, which are 20
usage-based or volumetric charges. 21
The Service Charge does not cover the fixed costs 22
incurred by residential customers and those fixed costs are 23
instead recovered through the volumetric Energy Charges. As 24
I explained above, the Energy Charges in Schedule 1 are 25
ASCHENBRENNER, DI 26
Idaho Power Company
also tiered, so that usage over a specific threshold in a 1
billing period are priced at a higher rate. 2
Q. What is the downside to this rate structure? 3
A. The Company’s current rate structure for 4
residential customers recovers a high proportion of fixed 5
costs through the volumetric Energy Charges instead of 6
through fixed charges. This relationship results in higher 7
energy use customers subsidizing lower energy use customers 8
and generally leads to customers believing the value of a 9
kWh of energy is much higher than it is. 10
Q. What costs does the Company propose are 11
reasonably recovered through the Service Charge? 12
A. The Company proposes to recover all costs 13
related to the distribution system and customer-related 14
costs like metering, billing, and customer service through 15
the Service Charge. It is appropriate to include these 16
costs in the fixed monthly charges that residential 17
customers pay because they represent the fixed costs to 18
deliver power over the distribution system and provide 19
customer service and billing functions. These costs are 20
fixed in nature and do not vary with changes in volumetric 21
energy usage. If a residential customer uses less energy, 22
the fixed costs of distribution facilities that have been 23
installed to serve that customer do not decrease. These 24
costs are therefore appropriately recovered through the 25
ASCHENBRENNER, DI 27
Idaho Power Company
fixed Service Charge. The Company proposes to continue to 1
recover all other costs – fixed generation and transmission 2
costs as well as variable energy costs – through Energy 3
Charges. 4
Q. Will this structure remove the energy 5
efficiency price signal? 6
A. No. As I mentioned, the Company is proposing 7
to continue to collect fixed charges associated with 8
generation and transmission through seasonal energy 9
charges, which will continue to promote energy efficiency. 10
As shown in Tables 6 and 7 of the Direct Testimony of Mr. 11
Anderson, in the first year of the change, the energy rates 12
are higher than they currently are – by the end of the 13
transition plan, the energy charges remain seasonally 14
differentiated, ensuring an efficiency signal remains. 15
Q. Did the Company consider the impact this rate 16
design would have on low-income customers? 17
A. Yes. As discussed in greater detail in the 18
Direct Testimony of Mr. Anderson, the Company evaluated the 19
impact of this rate design on those customers in its 20
service area known to be eligible for income-qualified 21
energy assistance and found the proposed rate design would 22
not disproportionally impact those customers in a negative 23
way. In fact, at the end of the transition period, these 24
ASCHENBRENNER, DI 28
Idaho Power Company
customers are more likely to see a savings when compared to 1
the residential customer class in total. 2
Q. Why is the Company proposing that these 3
changes occur over a three-year transition? 4
A. Essentially, the Company is mindful of the 5
impacts this type of a rate design will have on lower-usage 6
customers and with gradualism in mind, has proposed a 7
multi-year timeframe to moderate bill impacts on individual 8
customers. The three-year transition provides a mechanism 9
to make changes that better align rates with cost-of-10
service while also balancing how these changes affect some 11
customers. Mr. Anderson presents a bill impact analysis to 12
show the bill impact for customers once the plan is 13
implemented. 14
III. ON-SITE GENERATION 15
Q. Please summarize the Company’s request 16
presented in Case No. IPC-E-23-14. 17
A. On May 1, 2023, Idaho Power filed Case No. 18
IPC-E-23-14 (“ECR Case”).2 The Company filed the case in 19
response to Commission Order No. 35631 directing the 20
Company to file a new case to implement changes to its on-21

2 In the Matter of Idaho Power’s Application for Authority to Implement Changes to the Compensation Structure
Applicable to Customer On-Site Generation Under Schedules 6, 8, and 84 and to Establish an Export Credit Rate
Methodology, Case No. IPC-E-23-14 (filed May 1, 2023).
ASCHENBRENNER, DI 29
Idaho Power Company
site generation offering. Specifically, the Company 1
requested the Commission implement: (1) real-time net 2
billing with an avoided cost-based financial credit rate 3
for exported energy, (2) a methodology for determining 4
annual updates to the ECR, (3) a modified project 5
eligibility cap for commercial, industrial, and irrigation 6
(“CI&I”) customers, (4) related changes to the accounting 7
for and transferability of excess net energy financial 8
credits, and (5) updated tariff schedules necessary to 9
administer the modified on-site generation offering. 10
Q. Are there any interdependencies between the 11
General Rate Case and Case No. IPC-E-23-14? 12
A. Yes. The Company is addressing a variety of 13
issues related to Idaho Power’s on-site generation offering 14
in the ECR Case. However, because a GRC is an appropriate 15
venue to address CCOS and rate design, the Company did not 16
present any recommendations related to those items in Case 17
No. IPC-E-23-14. Rather, those topics have been addressed 18
within this case. Further, the Company believes it is 19
appropriate to address transitional considerations in the 20
context of rates and rate design within this docket as this 21
GRC is the first opportunity to evaluate how closely 22
revenue collection for the on-site generation customers 23
aligns with the allocation of costs to those classes. 24
ASCHENBRENNER, DI 30
Idaho Power Company
Q. How did the Company approach CCOS cost-1
allocation for on-site generation customers? 2
A. I requested load research statistics be 3
developed based on on-site generation customers’ 4
utilization of the system. I then directed Mr. Goralski to 5
rely on those statistics to complete cost-allocation to the 6
on-site generation customers. This required relying on only 7
a “delivered channel” of meter data for allocating 8
generation, transmission, and energy related costs and 9
looking at the maximum of both the “delivered channel” and 10
“received channel” in determining the allocation of 11
distribution plant. This is consistent with the real-time 12
measurement interval presented in the ECR Case. 13
Q. Did legacy status3 impact cost allocation? 14
A. No; the Company evaluated the cost to serve 15
all customers with on-site generation in the same manner, 16
regardless of legacy status. The type of compensation 17
structure applied to the billings for customers has no 18
bearing on measuring those customer’s utilization of the 19
system. In all cases, for all classes, the Company assessed 20
the classes’ energy and demand requirements in determining 21
cost allocation. The approach I described ensures on-site 22

3 The Company uses the term legacy to refer to those systems that the Commission has previously determined would continue to take NEM, under certain conditions, for a period of 25 years (also known as “grandfathered” systems).
ASCHENBRENNER, DI 31
Idaho Power Company
generation customers are not treated any different than 1
standard service customers. 2
Q. Are there any other areas related to on-site 3
generation that are being addressed in this docket rather 4
than in the ECR Case? 5
A. Yes. In Order No. 34046, the Commission 6
directed Idaho Power to evaluate rate design and 7
specifically “transitional rates.” In the ECR Case, the 8
Company proposed that any transitional considerations be 9
better addressed when evaluating the reasonableness of 10
pricing proposals in the GRC versus the ECR Case, which is 11
focused on the modification of the measurement interval 12
applied to excess net energy and the valuation of that 13
excess energy. 14
Q. What were the results of the CCOS for 15
Schedules 6 and 8? 16
A. The study, prior to the cap and spread process 17
described by Mr. Goralski, showed that the Schedule 6 and 8 18
classes should receive a 52 percent and 111 percent 19
increase, respectively, in their class revenue requirement. 20
These results demonstrate a large revenue deficiency for 21
Schedules 6 and 8 under current rates, relative to other 22
classes. 23
Q. Is the Company proposing rates for those 24
classes to target the CCOS revenue requirement? 25
ASCHENBRENNER, DI 32
Idaho Power Company
A. No. The Company believes it is reasonable to 1
consider transitioning Schedule 6 and 8 customers to cost 2
of service over a period of time. If the Company were to 3
rely on the underlying CCOS as a basis for revenue 4
allocation, those customers would experience relatively 5
large increases in this case. 6
Q. How did the Company establish revenue targets 7
for Schedules 6 and 8 for rate design purposes? 8
A. As a mitigation measure, the Company combined 9
the Schedule 6 class with all residential customers (and 10
Schedule 8 with all small general service customers) to 11
complete both the cap and spread and the rate design 12
process. That is, in this case Idaho Power proposes that 13
on-site generation customers take service from Idaho Power 14
under the same rates that all standard service customers 15
pay. 16
Q. Will this result in a subsidy? 17
A. Yes. Any class whose assigned revenue 18
requirement is more than the amount authorized will be 19
subsidized by other customer classes. 20
Q. Does the Company believe its proposal results 21
provides a reasonable and fair transition period for 22
Schedule 6 and 8 customers? 23
A. Yes. The Company believes this approach 24
results in a reasonable transition period for on-site 25
ASCHENBRENNER, DI 33
Idaho Power Company
generation customers and aligns with prior Commission 1
orders where the Commission has directed the Company to 2
evaluate transitional considerations as it proposes changes 3
that will impact on-site generation customers. 4
Q. How will Schedule 6 customers be impacted by 5
the Residential Price Modernization Plan? 6
A. Schedule 6 customers were included in the 7
determination of the revenue neutral rates developed as 8
part of the Residential Price Modernization Plan. It is 9
important to note that even at the end of the three-year 10
plan, Schedule 6 customers will still be contributing well 11
below their cost to serve. Idaho Power is not recommending 12
future changes be approved as part of this case, rather, 13
the Company will evaluate further rate design 14
considerations for on-site generation customers, as may be 15
necessary, in future rate proceedings. 16
IV. TARIFF ADMINISTRATION 17
Q. Is the Company proposing changes to its tariff 18
as part of this case? 19
A. Yes. The Company is requesting several 20
administrative and housekeeping edits to many of the rules 21
and schedules contained within its tariff. Additionally, I 22
directed Mr. Maloney to work with field and customer-facing 23
representatives to develop recommendations for updates and 24
additions necessary to administer the tariff in a manner 25
ASCHENBRENNER, DI 34
Idaho Power Company
that ensures equitable treatment and is transparent to 1
customers. 2
Attachment Nos. 1 and 2 to the application contains 3
the legislative and clean versions of the requested tariff. 4
V. CONCLUSION 5
Q. Does this conclude your direct testimony in 6
this case? 7
A. Yes, it does. 8
//9
ASCHENBRENNER, DI 35
Idaho Power Company
DECLARATION OF CONNIE G. ASCHENBRENNER 1
I, Connie G. Aschenbrenner, declare under penalty of 2
perjury under the laws of the state of Idaho: 3
1. My name is Connie G. Aschenbrenner. I am 4
employed by Idaho Power Company as the Senior Manager of 5
Rate Design in the Regulatory Affairs Department. 6
2. On behalf of Idaho Power, I present this 7
pre-filed direct testimony in this matter. 8
3. To the best of my knowledge, my pre-filed 9
direct testimony and exhibits are true and accurate. 10
I hereby declare that the above statement is true to 11
the best of my knowledge and belief, and that I understand 12
it is made for use as evidence before the Idaho Public 13
Utilities Commission and is subject to penalty for perjury. 14
SIGNED this 1st day of June 2023, at Boise, Idaho. 15
16 Signed: _________________________ 17 CONNIE G. ASCHENBRENNER 18
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