20230501Direct Aschenbrenner.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF IDAHO POWER
COMPANY’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
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CASE NO. IPC-E-23-14

IDAHO POWER COMPANY

DIRECT TESTIMONY

OF

CONNIE G. ASCHENBRENNER
RECEIVED
2023 May 1, 4:44PM
IDAHO PUBLIC
UTILITIES COMMISSION

ASCHENBRENNER, DI 1
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 11
a 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 2015, 24
I assumed responsibilities associated with Residential and 25

ASCHENBRENNER, DI 2
Idaho Power Company
Small General Service rate design, as well as regulatory 1
support associated with demand-side management (“DSM”) 2
activities. In 2016, I was promoted to a Senior Regulatory 3
Analyst, and my responsibilities expanded to include the 4
development of complex cost-related studies. In 2017, I 5
was promoted to Rate Design Manager for Idaho Power, and in 6
2019 I was promoted to my current role as Rate Design 7
Senior Manager. I am currently responsible for the 8
management of the rate design strategies of the Company, as 9
well as oversight of all tariff administration. In my 10
current role, I am one of the Company representatives at 11
its Energy Efficiency Advisory Group (“EEAG”) meetings. 12
Q. How is your testimony organized? 13
A. I begin my testimony by providing background 14
for this case including an introduction to the issues and 15
proposed solutions and an overview of the relevant 16
regulatory history. Next, I will provide additional details 17
and explanation regarding the role of on-site generation on 18
Idaho Power’s system and the need to modernize on-site 19
generation policies and practices to reflect the nuances of 20
the current environment. I will then discuss the Company’s 21
recommendations for reforming the on-site generation 22
offering within the scope of this docket as well as further 23
considerations that will be more properly considered in a 24
General Rate Case (“GRC”). In doing so I will also describe 25

ASCHENBRENNER, DI 3
Idaho Power Company
areas of overlap and interdependencies between this case 1
and a future GRC proceeding. Finally, I will address the 2
applicability of the Company’s proposed changes to legacy 3
and non-legacy customers. 4
I. INTRODUCTION 5
Q. What is the purpose of this case? 6
A. The Company is requesting approval to 7
implement changes to the structure and design of its on-8
site generation offering as directed by the Commission in 9
Case No. IPC-E-22-22, Order No. 35631. More specifically, 10
the Company proposes to implement changes related to how it 11
measures and compensates for excess net energy; Idaho Power 12
is also proposing several other modifications related to 13
the on-site generation offering, including a modified 14
project eligibility cap for those commercial, industrial, 15
and irrigation (“CI&I”) customers taking service under 16
Schedule 84. The Company is proposing these changes become 17
effective January 1, 2024, with non-legacy customers 18
transitioning on their January 2024 billing cycle. 19
Q. Please describe the Company’s current on-20
site generation offerings. 21
A. Under Idaho Power’s on-site generation 22
service offerings, retail customers can choose to install 23
their own electricity-generating equipment (most commonly 24
solar panels) at their home or business to offset some of 25

ASCHENBRENNER, DI 4
Idaho Power Company
their electric needs. These customers remain connected to 1
Idaho Power’s grid and are able to consume energy as needed 2
from Idaho Power’s system, and the vast majority also 3
export energy to the grid. Customers that generate their 4
own electricity and who wish to interconnect exporting 5
systems are billed under different rate schedules as 6
follows: Schedule 6, Residential Service On-Site Generation 7
(“Schedule 6”), Schedule 8, Small General Service On-Site 8
Generation (“Schedule 8”), and Schedule 84, Customer Energy 9
Production Net Metering Service (“Schedule 84”), which is 10
the schedule the Company’s CI&I customers take net metering 11
service under. 12
Alternatively, customers that do not want their 13
generation systems to export power to the electrical grid 14
may interconnect their non-exporting system so that they 15
consume all the energy generated on-site. These customers 16
continue to take service under the retail rate schedule 17
they qualify for based on the applicability of the 18
Company’s retail tariff schedules. Both exporting and non-19
exporting systems are subject to Schedule 68, 20
Interconnections to Customer Distributed Energy Resources 21
(“Schedule 68”), which applies to all systems connected in 22
parallel and outlines the requirements and process for 23
interconnection. In this case, the Company is not proposing 24
any changes to how non-exporting systems take service or 25

ASCHENBRENNER, DI 5
Idaho Power Company
interconnect under the Company’s tariff. 1
Q. What is the current compensation structure 2
applicable to customers with exporting systems? 3
A. The compensation structure currently 4
applicable to exporting systems is net energy metering 5
(“NEM”), or often commonly referred to as just “net 6
metering.” Under the NEM structure, customer-generators 7
receive a credit in kilowatt-hours (“kWh”) for any excess 8
energy and that credit can be applied to offset energy 9
within the current billing cycle and carry-forward credits 10
can be used to offset energy consumption in future periods. 11
Q. When was net metering initially adopted by 12
the Commission? 13
A. The Commission approved net metering for on-14
site generation in 2002, when the Company had very few 15
customers seeking to interconnect their generating systems 16
in parallel with Idaho Power’s grid.1 17
Q. Has the interest in on-site customer 18
generation changed since Schedule 84 was established in 19
2002? 20
A. Yes. The number of customers taking service 21
under an on-site generation service offering has grown 22

1 Prior to January 2014, net metering customers were compensated through
financial credits. This changed in 2014 with the implementation of kWh
crediting for excess net energy authorized by the Commission in Order
Nos. 32846 and 32872.

ASCHENBRENNER, DI 6
Idaho Power Company
exponentially. As seen in Figure 1, the number of on-site 1
generation customers has grown from approximately 360 in 2
2013 to more than 15,900 as of March 31, 2023 (including 3
pending applications). The Company has nearly 940 pending 4
applications (customers who have submitted applications but 5
who have not yet completed the interconnection process). 6
Concerns initially raised by Commission Staff (“Staff”) and 7
acknowledged by the Commission in Case No. IPC-E-01-39 8
(i.e., the likelihood that some of the costs of serving net 9
metering customers will be subsidized by other customers2) 10
have been greatly exacerbated by the rapid increase in on-11
site generation customers. 12
// 13
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2 In the Matter of the Application of Idaho Power Company for Approval
of a New Schedule 84 – Net Metering, Case No. IPC-E-01-39, Order No.
28951 at 5-6, 12 (Feb. 13, 2002) and Staff Comments at 3-5 (Dec. 21,
2001).

ASCHENBRENNER, DI 7
Idaho Power Company
Figure 1 1
Cumulative Exporting System Counts, 2013 – 1Q2023 2
3
Q. What changes to its on-site generation 4
offerings is the Company requesting in this case? 5
A. Idaho Power requests the Commission issue an 6
order effective January 1, 2024, directing it to implement: 7
(1) real-time net billing with an avoided cost-based 8
financial credit rate for exported energy, (2) a 9
methodology for determining annual updates to the ECR, (3) 10
a modified project eligibility cap for CI&I customers, (4) 11
related changes to the accounting for and transferability 12
of excess net energy financial credits, and (5) updated 13
tariff schedules necessary to administer the modified on-14
site generation offering. 15
Q. Why should the Commission implement changes 16
to the on-site generation offering? 17
A. The existing monthly NEM compensation 18
 ‐
 2,000
 4,000
 6,000
 8,000
 10,000
 12,000
 14,000
 16,000
 18,000
2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 1Q2023
Sy
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m
 Co
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Residential Commercial & Industrial Irrigation

ASCHENBRENNER, DI 8
Idaho Power Company
structure overvalues exports from on-site generation, which 1
if left unmodified, will lead to a continuation of growing 2
cost shift among customers. The Commission has confirmed 3
this finding in past regulatory cases3 but has also 4
recognized the importance of ensuring any changes to the 5
Company’s on-site generation service offering are well-6
reasoned and data driven, previously ordering the Company 7
to “comprehensively study the costs and benefits of on-site 8
generation on Idaho Power‘s system.”4 9
This directive was fulfilled in Case Nos. IPC-E-21-10
21 and IPC-E-22-22 with the Commission's acknowledgement of 11
the October 2022 Value of Distributed Energy Resources 12
Study (“VODER Study”)5: 13
[W]e believe that any changes to 14
Company’s NEM program should be well-15
supported by a comprehensive study using 16
robust, relevant, and publicly available 17
data and methods, which we believe the 18
Company’s October VODER Study provides.6 19
Q. Why is now the right time to make changes to 20
the on-site generation offering? 21
A. The instant case is the latest in a series of 22

3 See, e.g., Case Nos. IPC-E-12-27, IPC-E-17-13, and IPC-E-18-15.
4 In the Matter of Idaho Power Company’s Application for Authority to
Establish New Schedules for Residential and Small General Service
Customers with On-Site Generation, Case No. IPC-E-17-13, Order No.
34046 at 30-31 (May 9, 2018).
5 See Attachment 1.
6 In the Matter of Idaho Power Company’s Application to Complete the
Study Review Phase of the Comprehensive Study of Costs and Benefits of
On-Site Customer Generation & For Authority to Implement Changes to
Schedules 6, 8, and 84, Case No. IPC-E-22-22, Order No. 35631 at 28
(Dec. 19, 2022).

ASCHENBRENNER, DI 9
Idaho Power Company
cases spanning several years related to on-site generation, 1
each representing another incremental step towards fulfilling 2
the Commission's ultimate objective: 3
The Company's future net-metering 4
programs will be based on a credible and 5
fair study, developed with public input, 6
and will reasonably balance the interests 7
of customers with net metering, and 8
customers without net metering.7 9
In each of the prior cases, the Commission has issued 10
further guidance as to the scope of what changes can be 11
implemented outside of a GRC and who the potential changes 12
could apply to. The preceding case, Case No. IPC-E-22-22, 13
was a culmination of the Company’s efforts to implement the 14
Commission’s directives, and the resulting October 2022 15
VODER Study, having been found in that case to comply with 16
the Commission’s previous directives, provides a solid 17
foundation for the Company to make implementation 18
recommendations in this case. Further, while the Company 19
has been diligent in its communications with customers 20
about the potential for changes to the compensation 21
structure (measurement interval and export credit rate), 22
Company representatives continue to hear from customers who 23
have made investments or who are considering investments 24
that they were unaware that the structure could change. 25

7 In the Matter of the Application of Idaho Power Company to Study the
Costs, Benefits, and Compensation of Net Excess Energy Supplied by
Customer On-Site Generation, Case No. IPC-E-18-15, Order No. 34509 at
15 (Dec. 20, 2019).

ASCHENBRENNER, DI 10
Idaho Power Company
The Company believes the Commission should move 1
forward expeditiously to implement a structure that will 2
accurately measure, record, and value excess energy from 3
on-site generation customers. A modification to the on-site 4
generation offering will ensure every customer who chooses 5
to invest in on-site generation has more clarity around the 6
future structure and design of this offering. 7
II. OVERVIEW OF RELEVANT REGULATORY HISTORY 8
Q. What prompted Idaho Power to implement net 9
metering under Schedule 84? 10
A. Prior to the implementation of Schedule 84 11
in Case No. IPC-E-01-39, the Company had offered 12
interconnection for on-site generation under the terms of 13
Schedule 86, Cogeneration and Small Power Production Non-14
Firm Energy. The service offering was in place for a single 15
customer and consisted of applying a formula rate for 16
exported energy. At the time, because the Company was not 17
able to implement this as an automated option under its 18
billing system, a manual process was necessary to bill 19
customers taking service under that option. In an effort to 20
streamline and simplify the process, in November 2001 the 21
Company filed an application in Case No. IPC-E-01-39 22
requesting to implement Schedule 84. 23
Q. What were some of the drivers for requesting 24
implementation of retail rate NEM? 25

ASCHENBRENNER, DI 11
Idaho Power Company
A. At the time of the Company’s filing, the 1
Company’s meters had limited capabilities and could only 2
track inflows and outflows of energy on a single channel. 3
This meant the measurement of energy at the end of the 4
month was a “net” read of total inflows (i.e., energy 5
delivered to the customer) and total outflows (i.e., excess 6
energy received from the customer). The application of NEM 7
provided a simple way for a customer to interconnect an 8
exporting on-site generation system and for the Company to 9
administer billing, and was a practice commonly applied 10
throughout the industry. 11
Even at that time, there were concerns with the 12
limitations of the practice. For example, as noted by 13
Staff, crediting “customer generators at full retail rates 14
will pay customers more than the actual value of the 15
generation” and created a “likelihood that some of the 16
costs of serving net metering customers will be subsidized 17
by other customers.”8 These concerns were mollified by 18
restricting levels of participation, which at that time 19
seemed inconsequential given that, though net metering 20
rules had been in place since 1983, the Company only had 21
three net metering customers nearly 20 years later. 22
Q. Did the Company later take steps to address 23
some of the cost-shifting or subsidy concerns promulgated 24

8 Case No. IPC-E-01-39, Order No. 28951 at 5-6.

ASCHENBRENNER, DI 12
Idaho Power Company
by NEM? 1
A. Yes. The Company filed Case No. IPC-E-12-27 2
where it sought, in part, to modify the pricing structure 3
for residential and small general service customer’s taking 4
service under Schedule 84. At that time, the Company had 5
roughly 350 Schedule 84 customers and the aggregate 6
nameplate capacity of installed systems was nearing the 7
Commission’s previously established total Schedule 84 8
capacity limit of 2.9 megawatts (“MW”). In its final order 9
in the matter, the Commission declined to modify pricing, 10
noting “changes such as those proposed in this case – 11
including increasing the monthly customer charge, imposing 12
a new BLC charge, and reducing the energy charge” for only 13
a subset of customers “should not be examined in isolation 14
but should be fully vetted in a general rate proceeding.”9 15
Q. What prompted Idaho Power to file the next 16
case related to on-site generation? 17
A. In 2017, approximately four years after the 18
Commission’s prior ruling, the number of customers who had 19
installed or applied to install on-site generation had 20
grown to nearly 1,500 customers, with expected nameplate 21
capacity of over 11 MW. The Company had not filed a GRC and 22
had no near-term expectation of the need to file. The 23

9 In the Matter of Idaho Power Company’s Application for Authority to
Modify its Net Metering Service and to Increase the Generation Capacity
Limit, Case No. IPC-E-12-27, Order No. 32846 at 12-13 (Jul. 3, 2013).

ASCHENBRENNER, DI 13
Idaho Power Company
Company had concerns that customers who were installing on-1
site generation were doing so under the presumption of the 2
continuation of NEM. 3
As a result, the Company submitted an application in 4
Case No. IPC-E-17-13, where it sought to establish 5
Schedules 6 and 8 and asked the Commission to direct it to 6
file a generic docket which would seek to establish a 7
compensation structure for customer-owned on-site 8
generation that reflects both the benefits and the costs of 9
those installations on Idaho Power’s system. 10
Q. What was the outcome of Case No. IPC-E-17-11
13? 12
A. In Order No. 34046, the Commission removed 13
residential and small general service ("R&SGS”) customers 14
with exporting systems from Schedule 84 and created two new 15
tariff schedules: Schedule 6 and Schedule 8.10 Schedule 84 16
continued to define the terms for CI&I customers with 17
exporting systems. In order to more accurately assign the 18
appropriate share of fixed costs and unquantified benefits 19
of on-site customer generation, the Commission also 20
directed the Company to “initiate a docket to 21
comprehensively study the costs and benefits of on-site 22
generation on Idaho Power’s system, as well as proper rates 23
and rate design, transitional rates, and related issues of 24

10 Case No. IPC-E-17-13, Order No. 34046 at 30-31.

ASCHENBRENNER, DI 14
Idaho Power Company
compensation for net excess energy provided as a resource 1
to the Company.”11 2
Q. Did the Company initiate the docket as 3
ordered? 4
A. Yes. Pursuant to the Commission's directive, 5
Idaho Power initiated Case No. IPC-E-18-15 to study the 6
costs, benefits, and compensation of net excess energy 7
supplied by on-site customer generation on October 19, 8
2018.12 In that case, the Company, Staff, and various 9
stakeholders undertook a thorough, data-driven evaluation 10
of the Company’s on-site generation offering through a 11
number of meetings and settlement negotiations. Through 12
this collaborative process, the parties were able to reach 13
a compromise on a significant number of critical elements 14
to the Company's on-site generation offering ("Settlement 15
Agreement"). 16
Q. Did the Commission approve the Settlement 17
Agreement? 18
A. No. In Order No. 34509, the Commission 19
rejected the proposed Settlement Agreement. While the 20
Commission found that the parties had acted in good faith 21
and pursuant to Commission Rules of Procedure, the 22
Commission found the process did not satisfy the 23

11 Id.
12 Case No. IPC-E-18-15, Petition to Initiate a Docket (Oct. 19, 2018).

ASCHENBRENNER, DI 15
Idaho Power Company
requirements established in Case No. IPC-E-17-13.13 1
Q. What guidance did the Commission provide 2
regarding criteria for a study? 3
A. The Commission stated that no changes to the 4
Company's net metering offering would be considered until 5
Idaho Power prepared and filed a "credible and fair study" 6
of the costs and benefits of distributed on-site customer 7
generation meeting the following criteria: (1) the study 8
must use the most current data possible and must be readily 9
available to the public, and in the Commission's decision-10
making record; (2) the Company must design the study in 11
coordination with the parties and the public, and the 12
Commission will determine the final scope of the study; and 13
(3) Idaho Power must write the study, so it is 14
understandable to an average customer, but its analysis 15
must be able to withstand expert scrutiny.14 The Commission 16
also outlined the “study design” phase and a “study review” 17
phase that would be undertaken prior to a Commission 18
determination being issued on the benefits and costs of on-19
site generation on Idaho Power’s system. 20
Q. Did the Company comply with the Commission’s 21
directive to initiate the multi-phase process for a 22
comprehensive study? 23

13 Id., Order No. 34509 at 6.
14 Id. at 9.

ASCHENBRENNER, DI 16
Idaho Power Company
A. Yes. On June 28, 2021, Idaho Power applied 1
for the Commission to initiate a multi-phase process for a 2
comprehensive study of the costs and benefits of on-site 3
customer generation, as directed in Order No. 34046.15 After 4
considering more than 250 written public comments, oral 5
testimony at a public hearing, and written comments filed 6
by eleven parties to the proceeding, the Commission issued 7
Final Order No. 35284 approving a Study Framework detailed 8
therein. The Commission found that the Study Framework 9
“meets our directive for a credible and fair study” and 10
reminded Idaho Power to “use the most current data 11
possible” that is readily available to the public and 12
submitted to the Commission’s decision-making record.16 This 13
order concluded the “study design” phase of the process. 14
Q. Has the “study review” phase been completed? 15
A. Yes. Following the Commission’s Order in 16
Case No. IPC-E-21-21, the Company completed the VODER Study 17
in accordance with the foundational principles outlined by 18
the Commission and initiated Case No. IPC-E-22-22 to allow 19
for public, stakeholder, and Commission review of the 20
Study. The Company filed an initial study in June 2022; 21

15 In the Matter of Idaho Power Company’s Application to Initiate a
Multi-Phase Collaborative Process for the Study of Costs, Benefits, and
Compensation of Net Excess Energy Associated with Customer On-Site
Generation, Case No. IPC-E-21-21, Application (Jun. 25, 2021).
16 Id., Order No. 35284 at 9 (Dec. 30, 2021). See also, Case No. IPC-E-
18-15, Order No. 34509 at 9-10.

ASCHENBRENNER, DI 17
Idaho Power Company
however, in response to stakeholder and public comments, 1
the Company later submitted a revised VODER Study in 2
October 2022 for the Commission’s consideration. 3
In Order No. 35631, the Commission found “the 4
October VODER Study complies with our previous directives 5
and should serve as a basis for the Company’s 6
implementation recommendations in a subsequent case.”17 7
III. ON-SITE GENERATION ON IDAHO POWER’S SYSTEM 8
Q. Please explain the Company’s view on 9
customer generation. 10
A. The Company understands that some of its 11
customers desire to supply some of their energy needs 12
through on-site generation while relying on Idaho Power’s 13
system to serve the remaining energy needs not covered by 14
their on-site generation and as a means to export energy 15
for compensation. Idaho Power has a long history of 16
supporting customer choice and interest in renewable energy 17
and has demonstrated its ongoing commitment over the years 18
through various proposals intended to make it easier for 19
customers to participate in on-site generation, including: 20
 In 2016, Idaho Power proposed a change to Schedule 84 21
metering requirements18 in order to reduce barriers to 22
participation for primary service-level customers who 23

17 Case No. IPC-E-22-22, Order No 35631 at 28.
18 Idaho tariff advice No. 16-05.

ASCHENBRENNER, DI 18
Idaho Power Company
desired to install on-site generation by modifying 1
the requirements related to the second meter’s 2
location and voltage. The Company initiated the change 3
based on feedback from customers that wanted to 4
install net metering systems but found compliance with 5
the existing metering requirement to be cost 6
prohibitive. The proposed tariff changes made it 7
easier and less costly for CI&I customers to install 8
systems by allowing the Company the discretion in 9
determining the location of the second meter. 10
 In Case No. IPC-E-20-26,19 the Company asked the 11
Commission to further modify the metering requirement 12
under Schedule 84 from a two-meter to single-meter 13
requirement. The request to remove the two-meter 14
requirement for new Schedule 84 customers was based 15
on concerns voiced by customers, installers, and 16
stakeholders, of the incremental costs and 17
complexities that exist as a result of the two-meter 18
requirement.20 19

19 In the Matter of Idaho Power Company’s Application for Authority to
Modify Schedule 84’s Metering Requirement and to Grandfather Existing
Customers with Two Meters, Case No. IPC-E-20-26, Application (Jun. 19,
2020).
20 Id. at 5.

ASCHENBRENNER, DI 19
Idaho Power Company
 In Case No. IPC-E-20-30,21 Idaho Power sought, in part, 1
to implement interconnection rules for customers with 2
Distributed Energy Resources (“DERs”) that do not wish 3
to export excess energy to the Company. Notably with 4
respect to CI&I customers with non-exporting systems, 5
the Company requested that there be no limit on total 6
nameplate capacity, which enabled CI&I customers 7
greater flexibility to install systems where they can 8
consume all generation on-site. 9
The Company earnestly supports customer choice in 10
clean energy sources. Its attempts to modernize the 11
compensation structure for on-site generation are driven by 12
its desire to ensure that rates paid for excess generation 13
are fair and equitable to both generating and non-14
generating customers. 15
Q. Does NEM accurately measure customer usage 16
and exports? 17
A. No. Due to the simplified construct, the 18
Company calculates a single measurement at the end of a 19
billing period and if the customer has net consumption 20
(meaning they consumed more energy than they exported), 21
they are billed and compensated at the rates included in 22

21 In the Matter of Idaho Power Company’s Application for Authority to
Establish Tariff Schedule 68, Interconnections to Customer Distributed
Energy Resources, Case No. IPC-E-20-30, Application (Jul. 20, 2020).

ASCHENBRENNER, DI 20
Idaho Power Company
the applicable rate schedule. If the customer has net 1
exports over the billing period (meaning they exported more 2
energy than they consumed), they receive a kWh credit for 3
all excess energy that can be carried forward to other 4
billing periods. 5
Q. Why does the Company believe it is important 6
to accurately measure a customer’s exports and consumption? 7
A. The existing NEM structure results in the 8
under-measurement of both the amount of kWh consumed by the 9
customer as well as the kWh exported by the customer. That 10
is, throughout each day a customer may be exporting kWh at 11
certain times (when their on-site generation system is 12
producing more than their energy needs) and consuming from 13
the grid at other times (in the evening or at times when 14
the customer’s energy needs are more than their system is 15
producing); however, at the end of the billing period both 16
the number of consumed kWh and the number of exported kWh 17
are understated. This undermeasurement leads to the under-18
recovery of costs associated with utility-provided service 19
and the overcompensation of exported energy. As a result, 20
and potentially most impactful, it sends an incorrect price 21
signal to potential on-site generation customers. 22
IV. COMPANY’S IMPLEMENTATION PROPOSAL & INTERDEPENDENCIES 23
WITH UPCOMING GENERAL RATE CASE 24
Q. What were the primary objectives the Company 25
relied upon in developing its implementation proposal in 26

ASCHENBRENNER, DI 21
Idaho Power Company
this case? 1
A. The Company identified four primary 2
objectives as it developed its proposal: (1) recommend a 3
compensation structure that will accurately measure a 4
customer-generator’s use of the system – both in recording 5
exported energy and usage; (2) apply methods that will 6
result in a fair and accurate valuation of customers’ 7
exported energy; (3) implement a repeatable method for 8
updating the Export Credit Rate (“ECR”) that will ensure 9
timely recognition of changing conditions on Idaho Power’s 10
system and the broader power markets which may warrant 11
changes to the ECR; (4) balance accuracy with customer 12
understandability. 13
Application of these principles also provides the 14
Company the foundation for proposing changes to the project 15
eligibility cap and excess energy credits transfer process 16
that will provide additional flexibility and opportunities 17
for customers to install on-site generation. 18
Q. Please summarize the scope of this filing. 19
A. Generally, the focus of this filing is 20
related to modifications to the measurement interval 21
applied for measuring energy, valuation of the ECR, and 22
administrative items related to the implementation of an 23
avoided cost-based ECR. Coincident with changes to the 24
measurement interval and ECR valuation being approved, the 25

ASCHENBRENNER, DI 22
Idaho Power Company
Company is also seeking a change in how the project 1
eligibility cap is defined for Schedule 84 customers. 2
Q. Are there any items identified by the 3
Commission in Order No. 35631 the Company views as “out of 4
scope” for this filing? 5
A. Yes. The Commission has previously 6
determined that changes to rates for consumption is 7
appropriately considered in a GRC, when changes for all 8
customer classes are evaluated holistically.22 Because the 9
class cost-of-service (“CCOS”) is the first step in the 10
rate setting process, the Company will address that item in 11
its upcoming GRC.23 12
Q. Why did Idaho Power choose to file this 13
“stand-alone” case to address the compensation structure 14
for on-site generators instead of addressing all on-site 15
generation service matters in the GRC? 16
A. A GRC covers a broad range of issues related 17
to the cost and pricing for services Idaho Power provides 18
to its customers. Because of the relatively narrow scope of 19
issues in this case, the Company felt a separate case would 20
be the best way to ensure a transparent and thorough 21
vetting of the important items related to Idaho Power’s on-22

22 See, e.g., Case No. IPC-E-12-27, Order No. 32846 at 12-13; Case No.
IPC-E-18-15, Order No. 34509 at 15.
23 On April 1, 2023, Idaho Power filed Notice of Intent (“NOI”) to file
a General Rate Case. The NOI anticipates a GRC will be filed on or
after June 1, 2023.

ASCHENBRENNER, DI 23
Idaho Power Company
site generation offering. 1
Q. Are there any interdependencies between this 2
case and the Company’s upcoming GRC? 3
A. Yes. Please see Table 1 for a summary of the 4
items the Company was previously directed to evaluate in a 5
future filing.24 The table differentiates between topics the 6
Company is seeking approval in this case (ECR column) 7
versus those specific to the Company’s upcoming GRC (GRC 8
column). 9
// 10

24 Case No. IPC-E-22-22, Order No. 35631 at 28-31.

ASCHENBRENNER, DI 24
Idaho Power Company
Table 1 1
Export Credit Rate (“ECR”) Implementation & General Rate 2
Case (“GRC”) Interdependencies 3
ECR GRC Comments/Rationale
Measurement 
Interval 
(ECR)  ‒
Measurement interval to (1) inform the valuation of 
ECR and (2) measurement used for proposed net 
billing compensation structure. 
Measurement 
Interval 
(Cost‐of‐Service) ‒ 
Measurement interval to inform cost allocation. 
Interdependency exists with aligning measurement 
interval for ECR and compensation structure with 
CCOS.
Export Credit 
Rate  ‒
ECR methods presented for approval using real‐time 
measurement interval.
Transition
 
No proposed transition from retail rate to avoided 
cost ECR.  
Transitional considerations are appropriately 
addressed in the context of the ratemaking process 
which will be considered in the GRC.
ECR Updates
 ‒
Timing and methodology of annual updates for ECR.
Class Cost‐of‐
Service ‒ 
Basis for Schedule 6 and 8 class‐specific revenue 
requirement addressed holistically in GRC.
Export Credit 
Recovery  ‒
Method for recovery of ECR expenditures.
Project Eligibility 
Cap  ‒
Change to project cap coincident with approval of 
change in compensation structure to real‐time net 
billing.
Implementation/
Other  ‒
Other considerations include accumulated kWh 
credits and financial credit transfer rules.
/// 4

ASCHENBRENNER, DI 25
Idaho Power Company
As reflected in Table 1, the Company proposes to 1
address the majority of the items in this case, with only 2
CCOS being fully addressed in the GRC. There are a few 3
items to note when looking at the table. 4
First, as previously mentioned, the Company intends 5
to address CCOS in its upcoming GRC; however, the Company 6
was ordered to address “measurement interval” in this case, 7
which is relevant in both evaluating the measurement of 8
excess net energy and in allocating cost as part of the 9
CCOS study in a GRC. The former will be addressed through 10
the Company’s proposal in this proceeding and the latter 11
will be addressed in the upcoming GRC, expected to be filed 12
on or after June 1, 2023. 13
Second, the Commission has ordered Idaho Power to 14
evaluate transitional considerations for implementation of 15
changes to the on-site generation offering. As more fully 16
described later, and after careful consideration, the 17
Company is not proposing to transition to the ECR over a 18
period of time, rather the proposed changes will be in 19
effect after January 1, 2024. It is important to note, 20
however, that the upcoming GRC will be the first 21
opportunity to evaluate how closely revenue collection for 22
the on-site generation customers aligns with the allocation 23

ASCHENBRENNER, DI 26
Idaho Power Company
of costs to those classes. A previous analysis25 1
demonstrated the potential for a large revenue deficiency 2
in Schedules 6 and 8, and the Company believes it will be 3
important to carefully consider the impact to those classes 4
which may warrant transitional considerations, as it 5
develops its revenue spread recommendations. 6
Finally, the Commission directed Idaho Power to make 7
implementation recommendations as to both measurement 8
interval and compensation structure. However, because 9
“compensation structure” is essentially the combination of 10
the measurement interval and the ECR, the Company will 11
address compensation structure through the proposal for the 12
measurement interval and ECR. 13
Q. What measurement interval is the Company 14
proposing the Commission implement? 15
A. The Company is proposing to implement a 16
real-time net billing structure, where the meter will 17
record real-time net grid electricity consumption and 18
exports independently. That is, the meter will measure and 19
record all grid usage (energy in-flows) on one channel and 20
will separately measure all exports (energy out-flows) on a 21
different channel. Net billing, including a comparison of 22
hourly and real-time intervals, is more fully explained on 23

25 In the Matter of the Application of Idaho Power Company to Study
Fixed Costs of Providing Electric Service to Customers, Case No. IPC-E-
18-16, Motion to Accept Fixed Cost Report (Sep. 30, 2019).

ASCHENBRENNER, DI 27
Idaho Power Company
pages 17-24 of the October VODER Study.26 1
Q. Is real-time net billing the same as “buy-2
all, sell-all”? 3
A. No. The phrase “buy-all, sell-all” refers to 4
a construct where a utility may separately meter all 5
generation from a customer-generator at an interconnection 6
point that is separate from the meter installed to measure 7
and record all customer usage. In those arrangements, the 8
customer is not permitted to offset their usage with their 9
own generation; they are required to take full service from 10
the utility and separately sell back all generation for a 11
credit of some sort. That arrangement was not studied by 12
the Company and is not what the Company is proposing in 13
this case. 14
Q. How is the real-time net billing construct 15
different from “buy-all, sell-all”? 16
A. Under the real-time net billing construct, 17
the customer-generator will first consume any of their 18
generation on-site, behind Idaho Power’s meter. That is, 19
they are netting off their load with their own generation. 20
It is only the generation they are not consuming that is 21
exported to the grid at a defined ECR. 22
Q. Will the customer continue to receive a 1:1 23
kWh credit that can offset future kWh consumption? 24

26 See Attachment 1.

ASCHENBRENNER, DI 28
Idaho Power Company
A. No. Under the Company’s proposal, the 1
customer will generate a financial credit, based on the 2
product of measured exported energy and the ECR, that can 3
be monetized to offset current or future charges associated 4
with utility-provided service. 5
q. Why does the Company believe the ECR should 6
be modified? 7
A. The existing ECR is tied to the retail rate 8
of the customer generator’s standard service schedule. This 9
rate, however, is not reflective of the value of that 10
energy. The retail rate is designed to collect the 11
Company’s Commission-approved revenue requirement and 12
includes both fixed and variable related costs of providing 13
service. The product that customer-generators are exporting 14
to Idaho Power’s system is inherently different than the 15
service Idaho Power is providing to its customers. 16
Q. What was the Company’s focus specific to 17
development of the proposed ECR in this case? 18
A. The Company’s focus centered on developing a 19
methodology that would result in an ECR that fairly and 20
accurately reflects the value of energy on Idaho Power’s 21
system, while also balancing customer understandability and 22
a need for transparent pricing. Ultimately, the Company is 23
seeking to implement an ECR that strikes the necessary 24
balance of providing the right value to customers for their 25

ASCHENBRENNER, DI 29
Idaho Power Company
exports and ensuring the rest of the customers are paying 1
the right price for it in furtherance of the core 2
regulatory objective of leaving them indifferent to the 3
source of energy procured on their behalf. 4
Q. What is the Company’s proposed ECR? 5
A. In this filing, the Company is proposing to 6
establish a methodology that can be updated annually (each 7
June 1) and will provide customers with compensation based 8
on the actual settled market energy prices from the prior 9
calendar year. Company witness Ellsworth’s testimony 10
describes each of the benefit and cost streams and the 11
proposed methods that will be relied on for the annual 12
update and Company witness Anderson’s testimony describes 13
the Company’s proposed timing and procedural approach to 14
updating the ECRs annually. 15
See Figure 2 for the proposed ECRs to be in effect 16
from January 1, 2024 through May 31, 2024. 17
// 18
19
20
21
22
23
24
25
26
27
28
29
30
31

ASCHENBRENNER, DI 30
Idaho Power Company
Figure 2 1
Proposed Export Credit Rate 2
3
If its proposal is approved as filed, the Company 4
anticipates next updating the ECR in an April 2024 filing, 5
with new ECRs to be in effect June 1, 2024 through May 31, 6
2025. 7
Q. Is the Company proposing to modify rates for 8
consumption as part of this proceeding? 9
A. No. In this case, the Company is only 10
addressing the compensation rates for exported energy from 11
on-site generators. The Commission has previously found 12
that a GRC is the appropriate venue for modifying 13
Season ECR
Export Profile
Volume (kWh per kW) Annual 1,465
Capacity Contribution (%) Annual 8.76%
Export Credit Rate by Component (cents/kWh)
Energy On-Peak 8.59 ¢
Including integration and losses Off-Peak 4.91 ¢
Annual* 5.16 ¢
Generation Capacity On-Peak 11.59 ¢
Off-Peak 0.00 ¢
Annual* 0.79 ¢
Transmission & Distribution Capacity On-Peak 0.25 ¢
Off-Peak 0.00 ¢
Annual* 0.02 ¢
Total On-Peak 20.42 ¢
Off-Peak 4.91 ¢
Annual* 5.96 ¢
*Annual values provided for informational purposes only and reflect seasonal
weighting for 12 months ending December 2022.
Note: On-Peak defined as June 15 - September 15, Monday - Saturday (exluding
holidays), 3pm - 11pm. All other hours defined as Off-Peak.

ASCHENBRENNER, DI 31
Idaho Power Company
consumption rates for all customers. Accordingly, the 1
Company is not proposing any changes to the rates 2
applicable for utility-provided service in this docket. 3
Q. What is the revenue impact of implementing 4
real-time net billing for customers with non-legacy 5
systems? 6
A. Attachment 3 to the Application filed 7
coincident with my testimony provides a summary of the 8
overall revenue impact of this filing for each customer 9
class. As shown in Attachment 3, applying real-time net 10
billing to customers with non-legacy systems for the 11
January 2023 through December 2023 test year results in an 12
overall revenue increase of $4.5 million, or 0.41 percent. 13
V. APPLICABILITY OF CHANGES FOR NON-LEGACY CUSTOMERS 14
Q. Please explain the term “legacy” in the 15
context of the Company’s on-site generation offerings. 16
A. The Company uses the term legacy to refer to 17
those systems that the Commission has previously determined 18
would continue to take NEM, under certain conditions, for a 19
period of 25 years (also known as “grandfathered” systems). 20
More specifically, these systems will be eligible for the 21
continued application of full retail rate net metering 22
throughout the defined legacy period. 23
Q. Can you generally describe what systems 24
qualify for legacy treatment? 25

ASCHENBRENNER, DI 32
Idaho Power Company
A. Yes. In Case No. IPC-E-18-15, the Commission 1
found it was “prudent and justifiable to distinguish 2
between existing customers and new customers based on the 3
customer’s reasonable expectations when making significant 4
personal investments in on-site generation systems.”27 The 5
Commission found that prior to the service date of that 6
order (December 20, 2019) residential and small general 7
service customers “reasonably assumed the net-metering 8
program fundamentals would not change.”28 The Commission 9
established criteria29 to define legacy treatment for 10
existing systems under Schedule 6 and Schedule 8, which 11
would be subject to the rules in place as of the service 12
date of Order No. 34509, December 20, 2019. 13
Likewise, in Case No. IPC-E-20-26, the Commission 14
ultimately established criteria similar to that established 15
in Case No. IPC-E-18-15 to provide legacy treatment to 16
existing Schedule 84 systems (applicable to CI&I customers) 17
under the rules in place as of the service date of Order 18
No. 34854, December 1, 2020.30 19
Q. Are there requirements for a system to receive 20
continued legacy status? 21
A. Yes. All customers who initially qualified for 22

27 Case No. IPC-18-15, Order No. 34509 at 10.
28 Id.
29 See Id., Order No. 34509 at 14-15 and Order No. 34546 at 8-11 (Feb.
5, 2020).
30 Case No. IPC-E-20-26, Order No. 34854 at 11 (Dec. 1, 2020).

ASCHENBRENNER, DI 33
Idaho Power Company
legacy status will continue to receive legacy status 1
subject to the following conditions: 2
(1) the legacy status stays with the system at the 3
meter site; 4
(2) if the system is offline for over six months, or 5
is moved to another site, the legacy status is 6
forfeited; 7
(3) to allow for the replacement of degraded or 8
broken panels, the customer may increase the 9
capacity of the legacy system by no more than 10 10
percent of the originally installed nameplate 11
capacity or 1 kW, whichever is greater; and 12
(4) legacy status terminates after 25 years from the 13
relevant order (i.e., December 2045).31 14
Q. How many legacy and non-legacy customers does 15
the Company have? 16
A. As of March 31, 2023, the Company has a total 17
of 5,544 legacy systems and 9,429 non-legacy systems. Table 18
2 breaks down the customers by class and total installed 19
nameplate capacity. The Company also has 940 pending 20
customers (i.e., customers who have submitted an 21
application but who have not yet interconnected a system). 22
// 23
24

31 See Case No. IPC-E-18-15, Order No. 34546 at 9; Case No. IPC-E-20-26,
Order No. 34854 at 11.

ASCHENBRENNER, DI 34
Idaho Power Company
Table 2 1
Count of Legacy and Non-Legacy Systems by Customer Class - 2
March 31, 2023 3
Customer Segment Legacy Non-Legacy Total
Residential & Small General 5,177 9,379 14,556
Commercial & Industrial 160 42 202
Irrigation 207 8 215
Total Idaho 5,544 9,429 14,973
Q. To whom will the Company’s proposed changes 4
in this case apply? 5
A. Consistent with the Commission’s prior 6
directives, the Company proposes that modifications in this 7
case will apply to non-legacy customers taking service 8
under Schedules 6, 8, and 84. 9
Q. Did the Company consider proposing a 10
transition period whereby modifications wouldn’t apply for 11
some period of time? 12
A. The Company carefully considered whether a 13
transition period was warranted, but after reviewing the 14
relevant Commission orders and considering the extensive 15
communication the Company and Commission have done to 16
notify customers of the potential for change, the Company 17
does not believe it is prudent to continue to 18
overcompensate customers for their exported energy. 19
Q. Why does the Company disfavor a transition 20
period? 21
A. In developing its recommendation in this 22

ASCHENBRENNER, DI 35
Idaho Power Company
regard, the Company considered the substantial history on 1
this issue as summarized in Table 3, which provides an 2
overview of information regarding legacy status provided to 3
customers through Commission orders, direct customer 4
communication from the Company, or required to be provided 5
by solar retailers.32 As reflected in the table, the Company 6
has remained diligent in its efforts to notify customers of 7
the possibility for changes to the on-site generation 8
offering. 9
// 10

32 The Residential Solar Energy System Disclosure Act (codified in Idaho
Code Title 48, Chapter 18) defines persons who sell or lease
residential solar energy systems as “solar retailers.” Idaho Code 48-
1802(5).

ASCHENBRENNER, DI 36
Idaho Power Company
Table 3 1
Overview of Customer Communication and Notice of Future 2
Changes to On-Site Generation Offering 3
4
In what is likely the most direct communication with 5
each prospective customer, the Company has required every 6
customer generation applicant to sign an application 7
Date Communication Relevant Language
October 2019 Residential Solar Energy
System Disclosure Act
requires written disclosures
be provided by the
installer/seller to consumers
(Idaho Code 48-1805)
LEGISLATIVE OR REGULATORY ACTION MAY AFFECT OR ELIMINATE YOUR
ABILITY TO SELL OR GET CREDIT FOR ANY EXCESS POWER GENERATED BY THE
SYSTEM AND MAY AFFECT THE PRICE OR VALUE OF THAT POWER
December 2019 Commission Order No.
34509
"After the issuance of this Order, however, we believe it will no longer be reasonable for a
customer to assume the net-metering program fundamentals will remain the same over the
expected payback period of their investment."
January 2020 Idaho Power's Application
for On-Site Generation
Modified per Commission
Order
Customer must initial/sign
both disclosures on the
application
I understand that the net metering program design is subject to change including, but not limited to,
the interval length over which netting occurs, compensation for excess generation and the
interconnection requirements for on-site generation systems.
I UNDERSTAND THAT LEGISLATIVE OR REGULATORY ACTION MAY AFFECT OR
ELIMINATE MY ABILITY TO SELL OR GET CREDIT FOR ANY EXCESS POWER
GENERATED BY THE SYSTEM AND MAY AFFECT THE PRICE OR VALUE OF THAT
POWER. (ID RESIDENTIAL ENERGY SYSTEM DISCLOSURE ACT, ID CODE §§48-1801
§§48-1809)
January 2020 Company Email
Communications to
Prospective On-Site
Generation Customers
Modified to Include
Additional Language
The rules for on-site generation, including compensation structure, are outlined in Schedules 6, 8,
84 and 72, which have been approved by the Idaho Public Utilities Commission and the Oregon
Public Utility Commission (Commissions). Tariff schedules are subject to change with approval
from the Commissions. This means the rules in place today (including pricing, compensation
structure, excess energy value and system requirements) can change in the future. We will notify
you of any future changes to the schedules.
February 2020 Commission Order No.
34546
"We made it abundantly clear in Order No. 34509 that the program fundamentals are subject to
change. It would contravene our rationale to extend the date at which customers are eligible for
grandfathered status, and we therefore decline to do so."
December 2020 Commission Order No.
34854
"We find it prudent to make the determination on grandfathering existing Schedule 84 customer-
generators now, rather than waiting until a successor program is approved as many parties and
commenters suggested, because it clarifies to potential CI&I customer-generators that the
program fundamentals are undergoing a comprehensive review and are likely to change."
January 2021 Commission Order No.
34892
"No person, entity, business or organization should be representing that investment in and
installation of solar panels under a particular tariff will result in payback within a time certain
because the rates under the then current tariff do not become fixed at the time such an
investment is made"
June 2021 Company Press Release &
Bill Inserts Mailed to All
Customers
Customers who install on-site generation after the dates of those orders (December 20, 2019 for
Schedule 6 and 8; December 1, 2020 for Schedule 84) are subject to future changes to
compensation structure, including how much they are compensated for excess energy.
December 2021 Commission Order No.
35284
"We urge stakeholders in the on-site generation industry to be completely transparent with
potential investors. A utility’s rate schedules, including net-metering program fundamentals, are
subject to change. As such, there is no guaranteed return on investment."
June 2022 Company Press Release &
Bill Inserts Mailed to All
Customers
Customers who do not have legacy systems are subject to changes to the on-site generation
compensation structure, including the value of the ECR. Customers are notified when applying for
interconnection that the value of excess energy is subject to change.
December 2022 Commission Order No.
35631
"We are very concerned, though, by the number of commenters expressing worry that they will
be unable to pay off their solar panel investments if the NEM program changes...It should come
as no surprise to anyone who invested in an on-site generation solar system after December 20,
2019, that the Company may be authorized by the Commission to change fundamental aspects of
its NEM program—including the imposition of an ECR—which can affect the payback period for
customers."
January 2023 Commission Order No.
35667
"Contrary to Petitioner’s implication otherwise, the Order provides that customers 'should know
today that they will be getting a reduced credit for the electricity they generate.'"

ASCHENBRENNER, DI 37
Idaho Power Company
acknowledging they understand the program fundamentals can 1
change. Within weeks of the Commission issuing Order No. 2
34509 in Case No. IPC-E-18-15, the Company updated the 3
affirmative acknowledgement section in its application 4
(shown in Figure 3) to further clarify that the measurement 5
interval and compensation for excess energy is subject to 6
change. 7
Figure 3 8
Customer Application Acknowledgement 9
10
After careful review of the breadth of publicly 11
issued Commission orders, the extensive legal disclosures 12
required of installers, and Company efforts to ensure 13

ASCHENBRENNER, DI 38
Idaho Power Company
customer awareness of the potential for changes, the 1
Company believes customers should have reasonably 2
understood the fundamentals of the on-site generation 3
offering could change. 4
Q. Does the Company believe its recommendation 5
is consistent with prior Commission orders? 6
A. Yes. In its December 2022 order, the 7
Commission found: 8
We decline to rule, at this juncture, on 9
the appropriateness of a transitional 10
rate—this is a proposal more properly 11
explored during the implementation case. 12
However, we recommend that our previous 13
determinations and reasoning on legacy 14
systems in Order Nos. 34509, 34546, and 15
34892 inform any implementation proposal 16
brought before this Commission. 17
Q. Did the Company consider statements made by 18
customers in Case Nos. IPC-E-21-21 and IPC-E-22-22 that 19
they were unaware changes could apply to them? 20
A. Yes. While the Commission and Company have 21
been consistent in efforts to inform potential customers 22
about how future changes to the offering could impact them, 23
it is clear there are some customers who have been led to 24
believe otherwise. Likewise, some customers appear to have 25
not read or internalized the Company’s application 26
acknowledgment reproduced in Figure 3 and materials listed 27
in Table 3. 28
// 29

ASCHENBRENNER, DI 39
Idaho Power Company
In talking with Customer Solution Advisors (“CSAs”) 1
in the Company’s customer service center and other 2
customer-facing employees on the Company’s Customer 3
Generation team, I am aware that a number of customers have 4
indicated their installer did not tell them they would be 5
subject to future changes in the on-site generation 6
offering, and in many cases, have told the CSAs the 7
installer specifically told them they would receive legacy 8
treatment. 9
The Company is also aware of other customers who, 10
knowing that they would be subject to anticipated changes 11
to the on-site generation offering, are waiting to install 12
on-site generation until an order is issued outlining 13
changes to the offering. Shortly after the Commission 14
issued its December 2022 order acknowledging the October 15
2022 VODER Study, the Company received two email inquiries 16
from solar installers who actively followed and 17
participated in the IPC-E-22-22 proceeding. Both installers 18
inquired as to when the Company anticipated making an 19
implementation filing, with one noting they had potential 20
clients waiting to make investment decisions until a 21
determination had been made. 22
Q. Did the Company quantify the customer impact 23
of moving from NEM to a real-time net billing compensation 24
structure? 25

ASCHENBRENNER, DI 40
Idaho Power Company
A. Yes. As explained in the testimony of Mr. 1
Anderson, the Company evaluated the changes on non-legacy 2
customer bills that would result from moving to the real-3
time net billing compensation structure from the existing 4
NEM structure. The analysis showed impacts to customer 5
bills with an average increase of $12.12 per month33 as a 6
result of modifying the measurement interval and 7
implementing real-time net billing. 8
Q. Has the Commission provided any guidance on 9
whether the “payback” of a customer’s investment should be 10
considered in establishing an ECR? 11
A. Yes. In a recent order, the Commission 12
found: 13
the purpose of establishing a NEM rate is 14
not to ensure that customers who have 15
installed self-generation facilities are 16
able to recoup their investment or earn 17
a return on investment, it is to ensure 18
that customers are paid fair, just, and 19
reasonable rates for their exports and 20
non-self-generating customers are not 21
subsidizing the rates for self-22
generating customers.34 23
Q. Do you believe the bill impact supports 24
extending the “legacy” period through a transition from NEM 25

33 Average bill impact for non-legacy residential customer-generators.
Bill impact calculations for Schedule 6, 8, and 84, Anderson Exhibit
Nos. 6-8.
34 Case No. IPC-E-22-22, Order No. 35631 at 28 (emphasis in original).

ASCHENBRENNER, DI 41
Idaho Power Company
to real-time net billing? 1
A. No. For those customers that installed non-2
legacy systems prior to knowing the extent of changes to be 3
made to the on-site generation program, the pendency of the 4
regulatory proceedings has essentially provided a de facto 5
transition period, during which time customers have been 6
receiving NEM despite not qualifying for legacy status. The 7
Company does not believe it is appropriate to continue 8
maintaining NEM for non-legacy systems beyond January 1, 9
2024, when the Company’s proposed changes to the service 10
offering would take effect if approved by the Commission. 11
Based on the findings from the Commission-acknowledged 12
VODER Study, the continued application of NEM 1:1 retail 13
rate crediting is not representative of the value that 14
energy brings to the system. 15
VI. CONCLUSION 16
Q. Please summarize the Company’s request in this 17
case. 18
A. The Company is requesting approval to 19
implement changes to the structure and design of its on-20
site generation offering as directed by the Commission in 21
Case No. IPC-E-22-22, Order No. 35631. More specifically, 22
the Company requests the Commission issue an order 23
directing it to implement: (1) real-time net billing with 24
an avoided cost-based export credit rate, (2) a methodology 25

ASCHENBRENNER, DI 42
Idaho Power Company
for determining annual updates to the ECR, (3) a modified 1
project eligibility cap for CI&I customers, (4) related 2
changes to the accounting for and transferability of excess 3
net energy financial credits, and (5) updated tariff 4
schedules necessary to administer the modified on-site 5
generation offering. The Company is requesting the changes 6
apply to all non-legacy customers effective with their 7
January 2024 billing cycle. 8
Q. Does this conclude your testimony? 9
A. Yes. 10
// 11

ASCHENBRENNER, DI 43
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 is 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 May 2023, at Boise, Idaho. 15
16
17
Connie G. Aschenbrenner 18