20220630Anderson Direct.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

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 FOR NON-LEGACY SYSTEMS

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CASE NO. IPC-E-22-22

IDAHO POWER COMPANY

DIRECT TESTIMONY

OF

GRANT T. ANDERSON

ANDERSON, 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 Grant T. Anderson. My business address 4
is 1221 West Idaho Street, Boise, Idaho, 83702. I am employed by 5
Idaho Power as a Regulatory Consultant in the Regulatory Affairs 6
Department. 7
Q. Please describe your educational background. 8
A. In May of 2013, I received a Bachelor of Science 9
degree in Microbiology from Oregon State University. In May of 10
2015, I earned a Master of Business Administration degree from 11
Boise State University. In addition, I have attended the 12
electric utility ratemaking course The Basics: Practical 13
Regulatory Training for the Electric Industry, a course offered 14
through New Mexico State University’s Center for Public 15
Utilities. 16
Q. Please describe your work experience with Idaho 17
Power. 18
A. In 2018, I was hired as a Regulatory Analyst in the 19
Company’s Regulatory Affairs Department. My primary 20
responsibilities as a Regulatory Analyst included supporting the 21
Company's Commercial and Industrial customer classes’ rate 22
design and general support of tariff rules and regulations. In 23
2021, I was promoted to my current position as a Regulatory 24
Consultant. My responsibilities expanded to include the 25

ANDERSON, DI 3
Idaho Power Company
development of complex cost-related studies and support of the 1
Company’s Residential and Small General Service ("R&SGS") and 2
on-site generation customer classes’ rate design. 3
I. OVERVIEW 4
Q. What is the Company requesting in this case? 5
A. The Company is requesting the Idaho Public 6
Utilities Commission ("Commission") initiate the study review 7
and implementation phases of the comprehensive study of costs 8
and benefits of on-site customer generation (“Study”) as 9
outlined by the Commission in Order No. 34509.1 Specifically, the 10
Company requests the Commission (1) establish a formal process 11
and timeline for public review and comment on the Study; and (2) 12
issue an order acknowledging that the Study satisfies the 13
Commission directives outlined in Order Nos. 34046, 34509, and 14
35284, and directing modifications to the Company’s on-site 15
generation service offerings be implemented. The Company 16
envisions requests one and two would occur sequentially to first 17
allow for public vetting of the Study before stakeholders, 18
including the Company, take positions on recommended methods for 19
implementing a successor service offering for non-legacy on-site 20
customer-generator systems. 21
Q. Why is the Company proposing the Commission process 22
the case in this manner? 23

1 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 9-10 (Dec. 20, 2019).

ANDERSON, DI 4
Idaho Power Company
A. The Commission has previously found that before 1
authorizing changes to the Company’s on-site customer generation 2
offerings, it must “have a credible and fair study in front of 3
it before it can make a well-reasoned decision on the Company’s 4
net metering program design.”2 The Study itself does not advocate 5
for a single position regarding potential modifications to the 6
current net metering service, but rather explores several 7
methods of valuing customer-owned generation energy exports and 8
explores other important considerations. 9
While the Company ultimately intends to put forth a 10
recommendation for modifications to its on-site generation 11
service offerings as part of this case, the Company is first 12
requesting the Commission initiate the study review process to 13
allow the Commission Staff (“Staff”), intervenors, and members 14
of the public to examine and comment on the Study. Upon 15
completion of this Study review process, the Company intends to 16
consider the comments received on the Study and put forth a 17
recommendation for potential modifications to the on-site 18
customer generation service offerings. 19
In its application in this case (“Application”), the 20
Company has provided a proposed procedural schedule for the 21
Commission’s consideration that could allow for customers, 22
installers, and other stakeholders to have certainty regarding 23

2 Case No. IPC-E-18-15, Order No. 34509 at 9.

ANDERSON, DI 5
Idaho Power Company
changes to the Company’s on-site generation offering by the end 1
of 2022. 2
Q. Why does the Company believe the Commission should 3
consider issuing an order outlining certain changes to the on-4
site generation service offering as part of this case? 5
A. Dating back to 2017, parties to on-site customer 6
generation-related dockets in front of the Commission have cited 7
concerns regarding uncertainty for customers who may be 8
considering an on-site generation investment but do not have 9
information about how a successor tariff may be scheduled. 10
Some of the comments submitted in Case No. IPC-E-17-13 11
include: 12
 “An essential aspect of the City’s ability to meet 13
these goals is solar energy, and the viability of 14
solar energy here in Boise City, relies on 15
eliminating the uncertainty related to net metering 16
and providing predictability for customers currently 17
engaged or wishing to be part of Idaho Power’s net 18
metering program.”3 19
 “If Idaho Power’s proposal is accepted, Auric 20
Solar’s potential customers will be placed in an 21
untenable position of incurring a known, 22

3 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, City of Boise’s Memorandum
Joining in Support of, and Providing Comments to, Idaho Clean Energy
Association’s Motion to Dismiss at 5 (Oct. 27, 2017).

ANDERSON, DI 6
Idaho Power Company
substantial, up-front cost without knowing the long-1
term run.” “Auric Solar urges the Commission to 2
prevent this disruption” by ordering “that any 3
future application be carried out in a future 4
general rate case or other proceeding that will 5
fully evaluate the costs and benefits of distributed 6
energy generation, and that will provide certainty 7
after it is over.”4 8
 “The industry cannot sell a product that has such a 9
high level of uncertainty and unknowns.”5 10
Recently, the Clean Energy Opportunities for Idaho 11
(“CEO”) filed a petition seeking to modify the project 12
eligibility cap for Schedule 84, Customer Energy Production/Net 13
Metering Service ("Schedule 84") on-site generation systems.6 In 14
its response to Idaho Power’s Answer filed in the case, CEO 15
cites comments from agribusiness customers’ “need for urgency 16
and to address specific matters in 2022.”7 17
By issuing an order addressing certain changes to the on-18
site customer generation offering, the Commission can provide 19

4 Case No. IPC-E-17-13, Auric Solar LLC’s Joinder and Memo in Support of
ICEA’s Motion to Dismiss at 7 (Oct. 27, 2017).
5 Case No. IPC-E-17-13, Direct Testimony of Kevin King on Behalf of Idaho
Clean Energy Association, Inc. at 20 (Dec. 22, 2017).
6 In the Matter of Clean Energy Opportunities for Idaho’s Petition for an
Order to Modify the Schedule 84 100kW Cap & to Establish a Transition
Guideline for Changes to the Schedule 84 Export Credit Compensation Values,
Case No. IPC-E-22-12, CEO Petition (Apr. 28, 2022).
7 Case No. IPC-E-22-12, CEO Response to Idaho Power Company’s Answer and
Motion to Dismiss at 20 (Jun. 1, 2022).

ANDERSON, DI 7
Idaho Power Company
more clarity to current and future customers considering an 1
investment in on-site generation. 2
Q. How is your testimony organized? 3
A. My testimony begins with an overview of on-site 4
customer generation and the pertinent case history related to 5
the Commission's directive for the Company to comprehensively 6
study the costs and benefits of on-site customer generation. I 7
will provide a brief overview of the Study, which is included as 8
Attachment 1 to the Company's Application. I will describe the 9
stakeholder input that the Company received during the study 10
design phase and the development of the Study. Last, I will 11
describe key findings and implementation considerations. 12
II. CUSTOMER ON-SITE GENERATION – CURRENT STATUS & 13
STRUCTURAL CONSIDERATIONS 14
Q. What is on-site generation? 15
A. The Company uses the term "on-site generation" to 16
refer to its retail customers who choose to install equipment to 17
generate electricity to meet some of their electric needs. 18
Customers predominantly choose photovoltaic technologies – more 19
commonly known as solar panels. Customers that install equipment 20
to generate electricity remain connected to Idaho Power's 21
electric grid and consume energy as needed from Idaho Power's 22
system. The vast majority also export energy to the grid. 23
Q. Under which rate schedules do customers with on-24
site generation take service? 25

ANDERSON, DI 8
Idaho Power Company
A. Customers who install on-site generation can 1
interconnect an exporting system under the terms of Schedule 6, 2
Residential Service On-Site Generation ("Schedule 6"), Schedule 3
8, Small General Service On-Site Generation ("Schedule 8"), and 4
Schedule 84. Schedule 84 is the tariff schedule for the 5
Company's commercial, industrial, and irrigation ("CI&I") 6
customers to take net metering service. 7
In addition, customers who do not want their generation 8
systems to export power to the electrical grid may elect to 9
interconnect their non-exporting system, consuming all the 10
energy generated on-site. These customers continue to take 11
service under the retail rate schedule they qualify for based on 12
the applicability of the Company's retail tariff schedules. Both 13
exporting and non-exporting systems are subject to Schedule 68, 14
Interconnections to Customer Distributed Energy Resources 15
("Schedule 68"), which applies to all systems connected in 16
parallel and outlines the requirements and interconnection 17
process. 18
Q. How many customers currently have an exporting 19
system interconnected to Idaho Power’s grid? 20
A. As of May 31, 2022, Idaho Power had 12,322 active 21
and pending exporting systems under Schedules 6, 8, and 84. 22
Collectively, these customer systems represent approximately 118 23
MW of total nameplate capacity. Additional information regarding 24

ANDERSON, DI 9
Idaho Power Company
existing participation is included on pages in Section 2.1 of 1
the Study. 2
Q. What compensation and billing structure is 3
currently applied to Schedules 6, 8, and 84? 4
A. The compensation structure currently applicable to 5
these schedules is commonly called net energy metering or "net 6
metering." The on-site customer generators’ billing structure 7
for Schedule 6 and Schedule 8 is identical to the standard 8
service customer class – Schedule 1 and Schedule 7, 9
respectively. Customers that take service under Schedule 84 10
continue to take retail electric service under Schedule 9, Large 11
General Service (“Schedule 9”), Schedule 19, Large Power Service 12
(“Schedule 19”), or Schedule 24, Agricultural Irrigation Service 13
(“Schedule 24”). 14
Q. Please describe the elements of the net metering 15
compensation structure and the billing structure applied to net 16
usage. 17
A. In the context of on-site customer generation, the 18
compensation structure refers to the measurement interval over 19
which customers’ consumption and excess net energy amounts are 20
quantified and the method under which customers are credited for 21
excess net energy. Under Idaho Power’s existing net metering 22
compensation structure, when customers billed under Schedules 6, 23
8, and 84 generate more energy than they consume on-site, that 24
energy is exported to the grid, and they earn an energy credit 25

ANDERSON, DI 10
Idaho Power Company
for the excess energy produced in kilowatt-hours ("kWh"). The 1
on-site customer-generator is billed for net energy consumption 2
during a billing cycle (i.e., energy consumed during the billing 3
cycle, less energy generated during the same period, each 4
measured in kWh). In practice, the bi-directional meter "spins 5
backward" when the system generates more than the customer-6
generator uses, decreasing the meter's measurement of the 7
customer generator's net monthly kWh consumption. 8
Because on-site customer-generators receive an energy, or 9
kWh, credit for any excess energy produced, any such credits are 10
monetized at the applicable retail energy rate when applied 11
against future energy consumption. 12
The billing structure (i.e., rate design) for Schedule 6 13
and Schedule 8 includes a fixed charge intended to recover a 14
portion of the customer and demand-related costs. Schedule 84 15
customers’ billing structure also includes demand charges under 16
their standard retail service schedule (i.e., Schedule 9, 19, or 17
24) to recover a portion of demand-related costs. For all 18
customer classes, volumetric rates applied to monthly energy 19
consumption recover all variable costs and the remaining fixed 20
costs. Under the existing net metering compensation structure, 21
the customer is billed for their net monthly energy use, which 22
is the amount they use minus the amount they generate over the 23
monthly billing period. 24

ANDERSON, DI 11
Idaho Power Company
Q. Are Idaho Power's retail rates designed to consider 1
the unique load characteristics of customers with on-site 2
generation systems? 3
A. No. Idaho Power's current retail rates were 4
designed to align with the load characteristics of customers 5
with a single directional relationship with the electric grid. 6
For example, historically R&SGS electric rate designs bundled 7
nearly all electric services into kWh rates, charging customers 8
based on the total amount of energy consumption over the course 9
of the month. Larger non-residential rate designs also recover a 10
portion of fixed costs through demand and basic load capacity 11
charges. When applied to customers taking service only from the 12
utility, this structure represented a fair and reasonable 13
collection of service costs from customers. 14
A large portion of the Company's revenue requirement is 15
collected through volumetric energy rates, including costs 16
associated with all electrical system components, from 17
investment in generation resources to the meters installed on 18
customers' premises. Consequently, Idaho Power customers' energy 19
rates include the variable energy-related components of the 20
revenue requirement and fixed operations and maintenance and 21
plant-related costs associated with the generation, 22
transmission, distribution, and customer care. 23
Q. Does the existing net metering billing and 24
compensation structure provide the Company a reasonable 25

ANDERSON, DI 12
Idaho Power Company
opportunity to appropriately assign the costs associated with 1
on-site generation to customer-generators? 2
A. No. A customer who installs on-site generation does 3
so with the intent to offset their energy usage and reduce or 4
eliminate the volume of energy they consume from Idaho Power. 5
Because fixed costs do not vary with changes in the amount of 6
energy consumed from Idaho Power, the simplified rate design of 7
recovering fixed costs through a volumetric rate results in the 8
under-collection of fixed costs from these customers. 9
The Company's R&SGS customers have the most significant 10
portion of fixed costs – 91 percent8 - collected through the 11
volumetric energy charge. The Company’s irrigation, large 12
general service (commercial), and industrial customer classes 13
have 70, 60, and 39 percent of fixed costs collected through 14
volumetric charges. 15
Q. Are both compensation structure and billing 16
structure at issue in this case? 17
A. No. As more fully described below, the Commission 18
has ordered the Company to study changes to the compensation 19
structure, which will include the measurement interval and 20
export credit rate. In Order No. 35284, the Commission found 21
that “updates to current cost of service, new rate designs, and 22

8 Fixed costs collected through volumetric charges proportion is calculated
from inputs sourced from the Company’s most recent general rate case. See In
the Matter of the Application of Idaho Power Company for Authority to
Increase its Rates and Charges for Electric Service to its Customers in the
State of Idaho, Case No. IPC-E-11-08.

ANDERSON, DI 13
Idaho Power Company
transitional rates” are most appropriately implemented in a 1
general rate case.9 Therefore, only compensation structure for 2
customer-generators is at issue in this case for potential 3
modifications, or tweaks, to occur in advance of a general rate 4
case. 5
Q. Will modifying the compensation structure alone 6
ensure the Company has a reasonable opportunity address the 7
collection of fixed costs from on-site generation customers? 8
A. No, but the Company believes modifying the 9
compensation structure represents a meaningful step towards a 10
more fair and sustainable service offering. A change in the 11
compensation structure that includes a more granular measurement 12
of usage will provide an improved opportunity to more equitably 13
assign the costs necessary to provide service to on-site 14
generation customers. A change in the measurement interval would 15
also provide an opportunity to adjust the compensation for 16
excess net energy from the fully bundled retail rate to an 17
avoided cost rate. However, these two improvements are not a 18
complete solution. By continuing to apply the existing rate 19
design against the usage of customer-generators with exporting 20
systems, the Company will continue to under-collect the cost to 21
provide service from these customers. 22

9 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, Order No. 35284 at 24 (Dec. 30, 2021).

ANDERSON, DI 14
Idaho Power Company
III. RELEVANT PROCEDURAL HISTORY 1
Case No. IPC-E-17-13 2
Q. What did the Company request in its application in 3
Case No. IPC-E-17-13? 4
A. In Case No. IPC-E-17-13, Idaho Power explained that 5
the rates charged to net metering customers were not designed to 6
reflect the value of the service being provided to them. The 7
inaccuracies in pricing could result in cost-shifting between 8
customers who choose to install on-site generation and those who 9
do not. Idaho Power asked to first establish new customer 10
classes for R&SGS customers with on-site generation and then 11
establish a compensation structure for customer-owned 12
distributed energy resources ("DER") that reflects both the 13
benefits and costs that DER interconnection brings to the 14
electric system. 15
Q. Did the Commission acknowledge the limitations of 16
retail rate net metering? 17
A. Yes. In Order No. 34046, the Commission found: 18
Our analysis of the history of the Company’s 19
on-site generation program reveals an unfairness in 20
how current and future on-site generation customers 21
avoid fixed costs. The ability these customers have 22
to “net out” or net to zero their electricity use 23
causes them to underpay their share of the 24
Company’s fixed costs to serve customers, and this 25
inequity will only increase as more customers 26
choose on-site generation.10 27
28

10 Case No. IPC-E-17-13, Order No. 34046 at 16 (May 9, 2018).

ANDERSON, DI 15
Idaho Power Company
The Commission also found that "the present netting of energy 1
not only allows these customers to avoid paying their fair share 2
of fixed costs but also prevents them from realizing presently 3
unquantified benefits to the grid."11 4
Q. What was the outcome of Case No. IPC-E-17-13? 5
A. In Order No. 34046, the Commission removed R&SGS 6
customers with exporting systems from Schedule 84 and created 7
two new tariff schedules: Schedule 6 and Schedule 8.12 Schedule 8
84 continues to define the terms for CI&I customers with 9
exporting systems. In order to more accurately assign the 10
appropriate share of fixed costs and unquantified benefits of 11
on-site customer generation, the Commission also directed the 12
Company to “initiate a docket to comprehensively study the costs 13
and benefits of on-site generation on Idaho Power’s system, as 14
well as proper rates and rate design, transitional rates, and 15
related issues of compensation for net excess energy provided as 16
a resource to the Company.”13 The Commission encouraged the 17
parties to work through these issues together in compromise. 18
Case No. IPC-E-18-15 19
Q. Did the Company initiate a docket to 20
comprehensively study the costs and benefits of on-site customer 21
generation on Idaho Power's system? 22

11 Id. at 23 and 31.
12 Id. at 30-31.
13 Id.

ANDERSON, DI 16
Idaho Power Company
A. Yes. Pursuant to the Commission's request, Idaho 1
Power initiated Case No. IPC-E-18-15 to study the costs, 2
benefits, and compensation of net excess energy supplied by on-3
site customer generation on October 18, 2018.14 4
Q. Did the Company perform any studies related to 5
customers with on-site generation in that case? 6
A. Yes. The Company, Staff, and various stakeholders 7
evaluated the Company's on-site generation offering. Through 8
this collaborative process, the parties reached a compromise on 9
many critical elements of the Company's on-site generation 10
offering ("Settlement Agreement"). 11
Q. If approved, would the Settlement Agreement have 12
resulted in changes to the Company’s net metering program? 13
A. Yes. The proposed Settlement Agreement15 would have 14
changed several fundamental aspects of the Company's net 15
metering offering. Of note, customer-generators would have 16
netted energy production and consumption hourly instead of 17
monthly, and Idaho Power would have paid customers an export 18
credit rate for hourly net energy exported to the grid instead 19
of net excess energy being compensated at a 1:1 kWh credit. The 20
Settlement Agreement envisioned that R&SGS customers would 21

14 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, Petition to Initiate a Docket (Oct. 19,
2018).
15 Case No. IPC-E-18-15, Motion to Approve Settlement Agreement (Oct. 11,
2019).

ANDERSON, DI 17
Idaho Power Company
transition from retail rate monthly net metering to hourly net 1
billing at an export credit rate transition over eight (8) 2
years. Net exports would have been compensated at roughly half 3
the then current residential energy consumption rate. 4
Q. Did the Commission approve the Settlement 5
Agreement? 6
A. No. In Order No. 34509, the Commission rejected the 7
proposed Settlement Agreement. 8
Q. Why did the Commission reject the proposed 9
Settlement Agreement? 10
A. While the Commission found that the parties had 11
acted in good faith and pursuant to Commission Rules of 12
Procedure, the Commission found the process did not satisfy the 13
requirements established in Case No. IPC-E-17-13.16 14
Q. What guidance did the Commission provide regarding 15
criteria for a fair study? 16
A. The Commission stated that it would consider no 17
changes to the Company's net metering program until Idaho Power 18
has prepared and filed a "credible and fair study" of the costs 19
and benefits of distributed on-site customer generation meeting 20
the following criteria: (1) the study must use the most current 21
data possible and must be readily available to the public, and 22
in the Commission's decision-making record; (2) the Company must 23
design the study in coordination with the parties and the 24

16 Case No. IPC-E-18-15, Order No. 34509 at 6 (Dec. 20, 2019).

ANDERSON, DI 18
Idaho Power Company
public, and the Commission will determine the final scope of the 1
study; and (3) Idaho Power must write the study, so it is 2
understandable to an average customer, but its analysis must be 3
able to withstand expert scrutiny.17 4
Q. What process did the Commission establish for a 5
study? 6
A. In its Order, the Commission outlined a “study 7
design” phase and a “study review” phase. During the study 8
design phase, Staff and the Company will both “host public 9
workshops to share information and perspectives on net-metering 10
program design with the public and to listen to customer 11
concerns and input.”18 In the study review phase, the public will 12
have the opportunity to comment on whether the study 13
sufficiently addressed their concerns and opinions on what the 14
study shows.19 15
Q. Did the Commission issue any other directives in 16
Case No. IPC-E-18-15? 17
A. Yes. The Commission established criteria20 to 18
define legacy treatment for existing systems under Schedule 6 19
and Schedule 8. The legacy systems would be subject to the rules 20
in place as of the service date of Order No. 34509, December 20, 21
2019. 22

17 Id. at 9.
18 Id. at 9-10.
19 Id.
20 See Case No. IPC-E-18-15, Order No. 34509 at 14-15, and Order No. 34546 at
8-11 (Feb. 5, 2020).

ANDERSON, DI 19
Idaho Power Company
Q. What criteria did the Commission outline for legacy 1
systems? 2
A. A legacy system is defined as either an on-site 3
generation system interconnected with Idaho Power's system as of 4
the service date of Order No. 34509 or a customer with a binding 5
financial commitment to install an on-site generation system 6
that proceeds to interconnect their system on or before December 7
20, 2020.21 8
Q. Are the rates and rate structure subject to change 9
for legacy systems? 10
A. Yes. While legacy systems operate under the terms 11
of Schedule 6 or Schedule 8 as those Schedules existed on 12
December 20, 2019, rates and rate structure are subject to 13
change for legacy systems until and after legacy status 14
terminates on December 20, 2045.22 15
Q. How many legacy systems take service under Schedule 16
6 and Schedule 8? 17
A. As of May 31, 2022, approximately 5,300 legacy 18
R&SGS systems are interconnected to Idaho Power's system. 19
Case No. IPC-E-19-15 20
Q. Did the Company initiate a similar case for Idaho 21
Power’s Schedule 84 customer-generators? 22

21 Case No. IPC-E-18-15, Order No. 34509 at 14.
22 Case No. IPC-E-18-15, Order No. 34546 at 9.

ANDERSON, DI 20
Idaho Power Company
A. Yes. Idaho Power initiated Case No. IPC-E-19-1523 1
while the issues in Case No. IPC-E-18-15 were still under 2
Commission review. The Company's application highlighted 3
concerns that Schedule 84 customers were continuing to rely on 4
the expectation of the ongoing application of the net monthly 5
billing and compensation structure. Idaho Power asked the 6
Commission to initiate the new docket to consider similar issues 7
as to what was under review in Case No. IPC-E-18-15, but for 8
CI&I customers taking service under Schedule 84. 9
Q. How was Case No. IPC-E-19-15 processed? 10
A. Over the next several months, the Company and 11
parties engaged in similar settlement negotiations to those 12
occurring simultaneously in Case No. IPC-E-18-15. After the 13
Commission rejected the Settlement Agreement in Case No. IPC-E-14
18-15, Idaho Power withdrew its application, indicating the 15
matters related to compensation structure and export credit rate 16
for Schedule 84 would be appropriately considered in a future 17
comprehensive study, as prescribed by Order Nos. 34509 and 18
34546. 19
Case No. IPC-E-20-26 20
Q. Did the Company initiate a separate case to 21
determine if existing CI&I customer systems would receive legacy 22

23 In the Matter of Idaho Power Company’s Application for Authority to Study
the Measurement Interval, Compensation Structure, and Value of Net Excess
Energy for On-Site Generation Under Schedule 84 and to Temporarily Suspend
Schedule 84 Net Metering Service to New Idaho Applicants, Case No. IPC-E-19-
15.

ANDERSON, DI 21
Idaho Power Company
treatment before initiating the “study design” phase of the 1
study? 2
A. Yes. The Company initiated Case No. IPC-E-20-26 for 3
authorization to change Schedule 84's two-meter interconnection 4
requirement to a single-meter requirement for new customer-5
generators and establish legacy treatment for existing customer-6
generators under the current rules as of December 1, 2020.24 In 7
its filing, the Company represented that modification of the 8
metering requirement and transition to a single-meter 9
requirement will enable the Company to holistically study the 10
value of excess energy for all on-site generation in both the 11
R&SGS and CI&I customer classes. 12
Q. What was the outcome of Case No. IPC-E-20-26? 13
A. The Commission ultimately established criteria 14
similar to Case No. IPC-E-18-15 to provide legacy treatment to 15
existing Schedule 84 systems under the rules in place as of the 16
service date of Order No. 34854, December 1, 2020.25 The 17
Commission also acknowledged comments submitted regarding the 18
100 kW project eligibility cap and meter aggregation rules, but 19
ultimately declined to address them in that docket stating 20
“there will be opportunities to address these issues during or 21
after the forthcoming comprehensive study" and noted, "we look 22

24 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.
25 Case No. IPC-E-20-26, Order No. 34854 at 11 (Dec. 1, 2020).

ANDERSON, DI 22
Idaho Power Company
forward to the forthcoming comprehensive study and continued 1
engagement on these issues."26 2
Q. What criteria did the Commission outline for legacy 3
treatment for Schedule 84? 4
A. The Commission’s Order Nos. 34854 and 3489227 5
delineated between legacy and new systems subject to future 6
changes informed by a comprehensive study. A legacy system is 7
defined as either an on-site customer generation system 8
interconnected with Idaho Power's system as of the service date 9
of Order No. 34854 or a customer with a binding financial 10
commitment to install an on-site customer generation system that 11
proceeds to interconnect their system on or before December 1, 12
2021.28 13
Similar to Case No. IPC-E-18-15, the Commission 14
determined that Schedule 84 systems that qualify for legacy 15
treatment continue to be subject to changes in consumption rates 16
but not to changes in the 1:1 monthly kWh retail rate 17
compensation structure until legacy status terminates December 18
1, 2045.29 19
Q. How many legacy systems take service under Schedule 20
84? 21

26 Id. at 12.
27 Case No. IPC-E-20-26, Order No. 34892 (Jan. 14, 2021).
28 Id. at 9.
29 Case No. IPC-E-20-26, Order No. 34854 at 11.

ANDERSON, DI 23
Idaho Power Company
A. As of May 31, 2022, there are approximately 390 1
legacy Schedule 84 systems interconnected to Idaho Power's 2
system. 3
Case No. IPC-E-21-21 4
Q. Did the Company file to initiate the multi-phase 5
process for a comprehensive study? 6
A. Yes. On June 28, 2021, Idaho Power applied for the 7
Commission to initiate a multi-phase process for a comprehensive 8
study of the costs and benefits of on-site customer generation, 9
as directed in Order No. 34046.30 10
Q. Did the Company send communication to customers 11
that it had filed to initiate the study? 12
A. Yes. At the time of its filing, the Company sent a 13
bill insert to all existing customers, including R&SGS customers 14
(those taking service under Schedules 1, 6, 7, and 8) and CI&I 15
customers (those taking service under Schedules 9, 19, 24, and 16
84) notifying them of the Company’s application in the matter 17
and informing them how to participate in the docket. As part of 18
that case, the customer notification was necessary to ensure all 19
customer segments understood the Company was undertaking a study 20
process that would ultimately impact the Company’s on-site 21
generation offering for all customer classes. 22
Q. Was there broad representation of all customer 23
segments? 24

30 Case No. IPC-E-21-21, Application (Jun. 25, 2021).

ANDERSON, DI 24
Idaho Power Company
A. Yes. In total, 14 separate petitions to intervene 1
were submitted by parties. The parties represented individual 2
customers, environmental interests, installer groups, irrigation 3
customer interests, industrial customer interests, and a 4
municipality. 5
Q. What was the outcome of Case No. IPC-E-21-21? 6
A. After considering more than 250 written public 7
comments, oral testimony at a public hearing, and written 8
comments filed by eleven parties to the proceeding, the 9
Commission issued Final Order No. 35284 approving a Study 10
Framework detailed therein. The Commission found that the Study 11
Framework “meets our directive for a credible and fair study” 12
and reminded Idaho Power to “use the most current data possible” 13
that is readily available to the public and submitted to the 14
Commission’s decision-making record.31 15
Q. When did the Commission order the Study to be 16
completed? 17
A. The Commission ordered that the Company “complete 18
the study in 2022 as soon as feasible” and indicated that 19
“persons and parties will have another opportunity to 20
participate during the study review phase.”32 21
Q. Did the Commission’s order address any other 22
considerations? 23

31 Case No. IPC-E-21-21, Order No. 35284 at 9. See also Case No. IPC-E-18-15,
Order No. 34509 at 9-10.
32 Case No. IPC-E-21-21, Order No. 35284 at 32 and 10.

ANDERSON, DI 25
Idaho Power Company
A. Yes. The Commission reminded stakeholders in the 1
on-site generation industry to act with transparency when 2
engaging with potential investors and emphasized, yet again, 3
that “[a] utility’s rate schedules, including net metering 4
program fundamentals, are subject to change…[and][as] such, 5
there is no guaranteed return on investment.”33 In other words, 6
customers are not guaranteed a financial payback associated with 7
their investment. 8
Q. Has the Company completed the Study? 9
A. Yes. The Company’s completed Study is provided as 10
Attachment 1 to the Application. 11
IV. THE COMPREHENSIVE STUDY 12
Q. Given the approved scope of the study, what were 13
the Company’s primary objectives for the Study? 14
A. The primary objectives of the Study were to 15
evaluate the costs and benefits of on-site generation on Idaho 16
Power’s system fairly, objectively, and holistically. 17
Q. How did Idaho Power achieve these objectives? 18
A. The Company started with the foundational 19
principles outlined by the Commission in Order No. 34509. First, 20
the Commission found “the study must use the most current data 21
possible and the data must be readily available to the public, 22
and in the Commission’s decision making record.”34 The Company 23

33 Id. at 10.
34 Case No. IPC-E-18-15, Order No. 34509 at 9.

ANDERSON, DI 26
Idaho Power Company
largely relied on data from 2021 and has developed appendices to 1
the report that contain all data relied upon in development of 2
the Study. Those appendices will be posted on the Commission’s 3
website, in their native file formats, which will enable the 4
public to review, and if desired, perform analyses on the data. 5
The information is also contained in the decision-making record. 6
Second, the Commission directed the Company to “design 7
the study in coordination with the parties and the public, and 8
the final scope of the study will be determined by the 9
Commission.”35 Party and public comments received throughout Case 10
No. IPC-E-21-21 were critical in shaping the Study Framework 11
ultimately approved by the Commission. As I describe more fully 12
below, the Company also solicited feedback from parties and the 13
public while the Study was underdevelopment. The Company has 14
also proposed a case schedule that envisions public workshops to 15
be held by both the Company and Staff, as well as opportunities 16
for public hearings. 17
Finally, the Commission found “the study must be written 18
so it is understandable to an average customer, but its analysis 19
must be able to withstand expert scrutiny.”36 In the public 20
workshop held in May 2022, the Company asked members of the 21
public to comment on the understandability of the concepts being 22
described. The Company developed a glossary that is included in 23

35 Id.
36 Id.

ANDERSON, DI 27
Idaho Power Company
the Study and, where appropriate, utilized figures and images to 1
further enhance understandability of technical concepts. While 2
customer understandability was a high priority in the written 3
report, the underlying analysis relies on a robust technical 4
assessment of the costs and benefits of customer generation on 5
Idaho Power’s system. 6
As a result, I believe the Study has achieved the 7
Company’s primary objectives and has met the Commission’s 8
previous directives. 9
Q. How is the Study organized? 10
A. The Study is comprised of the following sections: 11
(1) executive summary; (2) introduction; (3) measurement 12
interval; (4) export credit rate; (5) frequency of export credit 13
rate updates; (6) compensation structure; (7) cost-of-service; 14
(8) recovering export credit rate expenditures; (9) project 15
eligibility cap; (10) other areas of study; and (11) 16
implementation considerations. The Study includes 31 appendices 17
which contain the underlying data and supporting documentation 18
for the information contained within the Study. To assist the 19
public in reviewing the Study and enhancing customer 20
understandability, it also includes a glossary that describes 21
key terms and acronyms used within the Study. 22
Q. Please provide an overview of what is contained in 23
each section of the Study. 24

ANDERSON, DI 28
Idaho Power Company
A. The Company was guided by the Commission’s approved 1
Study Framework in Order No. 35284. The Study includes the 2
following: 3
Introduction: An overview of on-site customer generation. 4
Section 2.1 provides a general background of on-site customer 5
generation and a snapshot of active and pending systems on Idaho 6
Power's system through May 31, 2022. Section 2.2 covers 7
pertinent regulatory history related to on-site customer 8
generation in Case Nos. IPC-E-17-13, IPC-E-18-15, IPC-E-19-15, 9
IPC-E-20-26, and IPC-E-21-21. This section also provides the 10
reader with an overview of the Commission-approved Study 11
Framework issued in Order No. 35284. 12
Measurement Interval: Following the Commission's approved 13
Study Framework, the Study evaluates and compares the base case 14
(net energy metering) against hourly and real-time measurements. 15
Export Credit Rate: This section evaluates each export 16
credit rate component as identified in the Study Framework. The 17
export credit rate includes the following general categories: 18
(1) avoided energy, (2) avoided generation capacity, (3) avoided 19
transmission and distribution capacity, (4) avoided line losses, 20
(5) avoided environmental costs, and (6) integration costs. Each 21
of these components has varying assumptions and methodologies 22
that have been evaluated within the Study and would result in 23
different outcomes for the effective export credit rate. 24

ANDERSON, DI 29
Idaho Power Company
Consistent with the Study Framework, the Study also considers a 1
flat and time-variant export credit rate structure. 2
Frequency of Export Credit Rate Updates: This section 3
considers the various data inputs to the export credit rate and 4
how these might reasonably be updated. In addition to the data 5
considerations, the Study also evaluates potential customer 6
impacts due to different frequencies of updates to the export 7
credit rate and how that might impact customers. 8
Compensation Structure: The compensation structure is the 9
metering and billing arrangement for customer-generators with 10
exporting systems. The Study evaluates bill impacts for an 11
average residential and small-general customer and all active 12
systems with 12 months of available data for 2021. The Study 13
evaluates Net Energy Metering, and Net Billing measurement 14
intervals with an export credit rate that falls within the range 15
of values studied to analyze customer bill impacts. 16
Class Cost-of-Service: The primary purpose of the cost-17
of-service study prepared for the on-site customer generation 18
study is to highlight the impact on cost-allocation between the 19
studied measurement intervals for the on-site generation 20
customer classes. The Study evaluates two cost-of-service 21
studies with underlying data for cost allocation based on the 22
two methods studied: hourly and real-time measurement. 23
Recovering Export Credit Rate Expenditures: The Study 24
evaluates how compensation for net excess energy should be 25

ANDERSON, DI 30
Idaho Power Company
accounted for and the potential applicability of the Power Cost 1
Adjustment ("PCA"). The study also considers customer classes' 2
cost recovery impact as directed by the Commission in the Study 3
Framework. 4
Project Eligibility Cap: The Study first evaluates the 5
existing project eligibility cap of 25 kW for R&SGS customers 6
and 100 kW for CI&I customers. Second, the Study considers a 7
modified cap at 100% and 125% of customer demand. 8
Other Areas of Study: First, the Study evaluates what 9
bill components the credit can offset. The Study then reviews 10
accumulated kWh credits and the potential for expiration and 11
transfer of financial credit balances. Last, the Study examines 12
customers' access to data to make informed decisions when 13
implementing a new compensation structure. 14
Implementation: The Study presents several considerations 15
for stakeholder and Commission consideration when evaluating the 16
timing of implementing changes to the net metering service 17
offering, including transitional rates. 18
Q. Will the Company notify customers that the Study 19
has been completed? 20
A. Yes. Idaho Power will issue a news release to 21
notify the public of its Application. 22
Idaho Power will also directly notify all existing 23
customers, including R&SGS customers (those taking service under 24
Schedules 1, 6, 7, and 8) and CI&I customers (those taking 25

ANDERSON, DI 31
Idaho Power Company
service under Schedules 9, 19, 24, and 84) of the Application 1
with a bill insert included with their next billing cycle. The 2
bill insert will notify all customers that Idaho Power has filed 3
a comprehensive study analyzing the benefits and costs of on-4
site customer generation within Idaho Power's service area. The 5
customer notice also explains that the Study provides 6
information that the Commission, Idaho Power, and other 7
stakeholders will use to determine what changes to Idaho Power’s 8
existing customer generation offering should be implemented and 9
the potential timing of that implementation. 10
A copy of the press release and customer bill insert are 11
included as Attachment 2 to the Application. 12
Q. How will the Company notify existing and pending 13
on-site generation customers of the filing? 14
A. In addition to receiving the bill insert, the 15
Company will send direct-mail letters to all existing and 16
pending on-site generation customers notifying them of the case. 17
Legacy customers will receive a letter notifying them that the 18
Company has filed the Study with the Commission, reminding them 19
of legacy status and how to maintain legacy status, and will 20
provide information on how they can participate in the 21
proceeding. Non-legacy customers will receive a letter notifying 22
them that Company has filed the Study with the Commission, 23
informing them they may be impacted by the outcome of the case, 24
and will provide information on how they can participate in the 25

ANDERSON, DI 32
Idaho Power Company
proceeding. A draft of the letters is included as Attachment 3 1
to the Application. 2
Q. Will the public have an opportunity to review the 3
data contained within the Study? 4
A. Yes. The Company has proposed a schedule in its 5
Application for consideration that seeks public input on the 6
Study and public recommendations for methods to be implemented 7
to a successor on-site generation offering. The Study is 8
provided as Attachment 1 to the Application and can be found on 9
the Company's website at www.idahopower.com/study. In addition 10
to the Study, Idaho Power has made all supporting data 11
available.37 12
V. STAKEHOLDER INPUT 13
Q. Did the Company seek stakeholder input regarding 14
the Study following the Commission’s order issued in Case No. 15
IPC-E-21-21? 16
A. Yes. After receiving the Commission order, the 17
Company began compiling data and completing the Study per the 18
Commission's directives. On April 19, 2022, the Company issued a 19
press release notifying the public of a public workshop to be 20
held on May 2, 2022. The press release informed the public that 21
"the workshop will focus on the export credit rate – the amount 22
customers with on-site generation systems, such as rooftop solar 23
panels, are credited for the excess energy they send back to 24

37 See Appendix Nos. 3.1-10.1 for supporting detail to the Study.

ANDERSON, DI 33
Idaho Power Company
Idaho Power's grid." Additionally, the press release notified 1
the public that during the workshop, Idaho Power would “share 2
information on the possible methods for evaluating the export 3
credit rate” and the workshop would be an opportunity for 4
“customers and interested stakeholders to provide feedback to 5
the Company.”38 A copy of the press release for the workshop is 6
included as Exhibit 1 of my testimony. The Company also sent 7
notice to all parties in Case No. IPC-E-21-21 informing them of 8
the workshop and how to participate. 9
Q. Please provide an overview of the workshop. 10
A. In addition to several parties to previous cases, 11
more than 40 members of the public attended the workshop, and a 12
recording and copy of the presentation materials were made 13
publicly available on Idaho Power’s website following the 14
workshop. At the workshop, the Company presented an overview of 15
the methodologies identified within the Study Framework and 16
asked for public feedback regarding the methods under Study for 17
determining the value of excess net energy. The presentation is 18
included as Exhibit 2 of my testimony. 19
Q. Why did the Company focus on the export credit rate 20
components at the workshop? 21
A. Throughout Case No. IPC-E-21-21, most public 22
comments and parties’ interest in the case centered on the 23
compensation for excess net energy. As a result, the Company 24

38 Exhibit 1

ANDERSON, DI 34
Idaho Power Company
felt it was essential to provide an overview at a public 1
workshop and seek to solicit feedback from the public and 2
parties related to how the Company was addressing that specific 3
part of the Study. 4
Q. What feedback did the Company receive from public 5
comments after the Company’s workshop? 6
A. The Company received five comments from the public 7
and one comment from CEO, which are included as Exhibit 3 of my 8
testimony. Generally, the public comments discussed the need for 9
affordability and accessibility of solar generation and 10
highlighted that environmental and societal benefits should 11
drive Idaho Power to incentivize and promote customer 12
generation. Two comments mentioned a perceived unfairness with 13
"changing rates" for non-legacy customers. Comments also 14
expressed a desire for a fair study and an understandable 15
report. 16
Q. What comments did the Company receive from CEO 17
after the workshop? 18
A. CEO provided comments on four topics that they 19
suggest should be included within the study: (1) CEO suggests 20
that Idaho Power consider the potential for customer-generator 21
exports to allow Idaho Power to avoid costs associated with 22
purchasing additional renewable energy credits (“REC”); (2) CEO 23
proposed Idaho Power consider whether it could provide 24
incentives to reduce the cost for customers to install on-site 25

ANDERSON, DI 35
Idaho Power Company
generation to avoid distribution system upgrades; (3) CEO 1
suggested that time-of-use (“TOU”) rates would be better focused 2
on incenting changes in consumption patterns than the export 3
credit rate; (4) CEO believes the study should address the value 4
of exports from customers with on-site generation in reducing 5
fuel price risk. 6
Q. Does the Study address CEO's comment regarding the 7
potential for customer exports to avoid costs associated with 8
purchasing additional RECs? 9
A. Yes. Section 4.5.2 of the Study, Crediting 10
Customers for Value of Renewable Energy Credits, addresses CEO’s 11
comment regarding avoiding costs associated with purchasing 12
additional RECs. The Study explains the complexity involved in 13
certifying and tracking generation in a manner that would allow 14
for RECs to be issued for a customer’s resource. 15
Q. Did Idaho Power consider alternative incentives for 16
on-site customer generation systems interconnected in locations 17
that avoid distribution system upgrades? 18
A. Yes. Section 4.3.1 of the Study, Transmission and 19
Distribution Capacity Cost: Method and Assumptions, discusses 20
this proposed alternative incentive. Such an incentive would 21
depend on sufficient exported energy that coincides with the 22
locational transmission or distribution peak load. Additionally, 23
the Commission stated that for the “scope of this case, all 24

ANDERSON, DI 36
Idaho Power Company
costs associated with on-site generator exports will be 1
reflected in the ECR.”39 2
Q. Has Idaho Power considered CEO's suggestion for TOU 3
rates being better for incenting changes in consumption patterns 4
than the export credit rate? 5
A. Yes. The Company is not opposed to evaluating TOU 6
rates for consumption. However, the Commission stated that new 7
rate designs are outside the scope of this Study.40 For the 8
Study, the Commission noted that the value of exported energy to 9
the system varies at different times of the day, week, month, 10
and year and that it would be appropriate to study peak-hour 11
pricing or another variable pricing mechanism for the export 12
credit rate. The Study considered both a flat and time-variant 13
export credit rate. 14
Q. Did the Study evaluate the value from customer-15
generator exports related to fuel price risks? 16
A. Yes. As discussed in more detail in Section 4.1 of 17
the Study, Avoided Energy Costs, this evaluation depends on the 18
energy input selected for implementation. For example, actual 19
market prices would account for the value of customer-generator 20
exports related to fuel price risks – whereas forecasted prices 21
would not. However, the Commission's decision for implementation 22
will have to weigh the benefits of maximizing the value of the 23

39 Case No. IPC-E-21-21, Order No. 35284 at 14.
40 Id. at 24-25.

ANDERSON, DI 37
Idaho Power Company
export credit rate when market prices are high versus providing 1
customer-generators stability and certainty. 2
VI. KEY FINDINGS AND IMPLEMENTATION CONSIDERATIONS 3
Q. Did the Company identify any key takeaways or 4
findings from the Study? 5
A. Yes. There are several key findings supported by 6
the Study. First, it is clear from the Study that the Company 7
has the technical capability to reduce the measurement interval 8
for on-site generation exports and that such a modification 9
would improve the accuracy of cost assignment and compensation 10
for on-site generation customers. Second, the Study presents 11
multiple valid methods of valuing excess energy from on-site 12
generators, each of which differ materially from current retail 13
energy rates, suggesting consideration of modifications is 14
warranted. Lastly, the Study presents several implementation 15
considerations that can adequately inform the appropriate timing 16
of transitioning to a successor service offering. 17
Q. Has the Company developed a recommendation for 18
addressing these items as part of its Application in this 19
matter? 20
A. No. The Company has not yet developed a 21
recommendation for the Commission’s consideration; however, it 22
proposes to do so as part of this case. The Company believes its 23
ultimate recommendation will be best guided and informed by 24

ANDERSON, DI 38
Idaho Power Company
feedback and input received from parties to the case and members 1
of the public. 2
Q. When does the Company propose it will make a 3
recommendation for modifications to the on-site generation 4
service offering? 5
A. As more fully described in the Company’s 6
Application, the Company has proposed a schedule for 7
consideration that could facilitate the Company and other 8
parties making recommendations to the Commission in the early 9
fall of this year. That schedule could allow for a Commission 10
order establishing changes to the service offering to be issued 11
by the end of the year. 12
Q. Has the Company considered what aspects of the on-13
site generation service offering could be modified as part of 14
this case? 15
A. Yes. The Company anticipates recommendations would 16
address the following: 17
 Compensation Structure – Recommendations on (1) a 18
proposed measurement interval; (2) export credit 19
rate value and structure. 20
 Frequency of Updates – Recommendations on the 21
appropriate frequency of export credit rate updates 22
to balance customer stability and the need for 23
regular updates to track avoided costs. 24

ANDERSON, DI 39
Idaho Power Company
 Recovery of Export Credit Expenditures – 1
Recommendations on the mechanism to recover export 2
credit expenditures. 3
 Project Eligibility Cap – Recommendations related to 4
the project eligibility cap for exporting systems. 5
 Transitional Rates – Recommendations on the need for 6
a transitional period to a modified export credit 7
rate, including the appropriate timing to 8
transition. 9
Q. Does the Company anticipate potential modifications 10
to the on-site generation service offering occurring 11
concurrently with a Commission order issued at the end of 2022? 12
A. No. The Company has asked the Commission to allow 13
for the implementation of potential changes over at least a 5-14
month period, meaning any Commission-approved changes to the on-15
site generation service offering would not occur before June 1, 16
2023. This time would allow for the evaluation of actions 17
necessary before implementation, including required system 18
configurations, tariff updates, and customer and installer 19
communication. 20
Q. What implementation considerations would need to be 21
evaluated before the effective date of a successor service 22
offering for non-legacy on-site customer-generator systems is 23
ordered? 24

ANDERSON, DI 40
Idaho Power Company
A. If the Commission authorizes a successor service 1
offering for non-legacy on-site customer-generators, the Study 2
contemplates two primary areas of consideration: (1) 3
transitional rates and (2) administrative updates and 4
communication materials. 5
Q. What would need to be considered as it relates to 6
transitional rates? 7
A. Section 11.1 of the Study, Transitional Rates, 8
addresses this topic. The Study does not propose a specific 9
proposal for implementation but recognizes that the Commission, 10
with input from parties, the public, and the Company, can assess 11
if a transition period is fair, just, and reasonable for on-site 12
customer-generators with non-legacy systems once changes to the 13
compensation structure are known. 14
Q. What implementation considerations would need to be 15
addressed regarding administrative updates and communication 16
materials? 17
A. Several considerations would need to be addressed 18
before a Commission authorized effective date for changes to on-19
site customer generation offering. If the Commission issued an 20
order by December 31, 2022, directing changes to the on-site 21
customer generation offering, Idaho Power would plan to 22
implement those changes as early as June 1, 2023. A five-month 23
implementation schedule would allow for the following activities 24
to be completed. 25

ANDERSON, DI 41
Idaho Power Company
System Changes: Idaho Power’s existing meters can measure 1
consumption and excess net energy on a net hourly or a real-time 2
basis, and its billing system can perform Net Billing. However, 3
some configuration would be required to implement that 4
functionality. Idaho Power would also need to re-design the bill 5
and ensure customers can access billing data via the Company’s 6
online portal, My Account. 7
Tariff Changes: Idaho Power anticipates that 8
modifications to the on-site customer generation offering may 9
require changes to at least Schedules 6, 8, 68, and 84. Idaho 10
Power anticipates holding technical workshops with Commission 11
Staff, installers, and other interested stakeholders to discuss 12
proposed tariff modifications necessary to incorporate the 13
Commission’s ultimate findings before submitting tariff changes 14
for the Commission's review and approval. This process could 15
occur over the first few months of 2023, with a compliance 16
filing submitted before the Commission’s ordered effective date. 17
Customer Communication: Robust customer communication 18
will be necessary before implementing modifications to the on-19
site customer generation offering. Idaho Power would ensure 20
customer service and other customer-facing employees are trained 21
to respond to customer inquiries before customer communications 22
detailing the changes are distributed and updated on Idaho 23
Power’s website. 24

ANDERSON, DI 42
Idaho Power Company
Installer Communication: Idaho Power has more than 50 1
installers known to be operating in its service area. 2
Communication with those installers is critical to ensure they 3
understand how Idaho Power’s customers will be impacted by 4
changes to the on-site customer generation offering. 5
VII. CONCLUSION 6
Q. Please summarize the Company’s request in this 7
case. 8
A. The Company requests the Commission (1) establish a 9
formal process for public review of, and comment on, the Study 10
and (2) issue an order acknowledging that the Study satisfies 11
the Commission directives outlined in Order Nos. 34046, 34509, 12
and 35284, and directing modifications to the Company’s on-site 13
generation service offerings be implemented. The Company 14
envisions to first allow for public vetting of the Study before 15
stakeholders, including the Company, take positions on 16
recommended methods for implementing a successor service 17
offering for non-legacy on-site customer-generator systems. 18
Q. Does this conclude your testimony? 19
A. Yes. 20

ANDERSON, DI 43
Idaho Power Company
DECLARATION OF Grant T. Anderson 1
I, Grant T. Anderson, declare under penalty of perjury 2
under the laws of the state of Idaho: 3
1. My name is Grant T. Anderson. I am employed by 4
Idaho Power Company as Regulatory Consultant in the Regulatory 5
Affairs Department. 6
2. On behalf of Idaho Power, I present this pre-7
filed direct testimony and Exhibit Nos. 1, 2 and 3 in this 8
matter. 9
3. To the best of my knowledge, my pre-filed direct 10
testimony and exhibits are true and accurate. 11
I hereby declare that the above statement is true to the 12
best of my knowledge and belief, and that I understand it is 13
made for use as evidence before the Idaho Public Utilities 14
Commission and is subject to penalty for perjury. 15
SIGNED this 30th day of June 2022, at Boise, Idaho. 16
17
18
Signed: _______________________ 19
20

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-22

IDAHO POWER COMPANY

ANDERSON, DI

TESTIMONY

EXHIBIT 1
Idaho Power Seeks Public Input on Customer Generation Study
April 19, 2022
BOISE, Idaho — Idaho Power is currently developing a study related to the costs and benefits of
customer-owned generation sources, such as rooftop solar, and is set to host a public workshop for
customers and interested stakeholders to provide feedback to the company. The workshop is set for 6
p.m. Monday, May 2, and will be held virtually with WebEx and dial-in options.
In December 2021, the Idaho Public Utilities Commission (IPUC) issued an order in case IPC-E-21-21
directing Idaho Power to complete a comprehensive study of the costs and benefits of on-site
generation on the electrical grid. The workshop will focus on the export credit rate — the amount
customers with on-site generation systems, such as rooftop solar panels, are credited for excess energy
they send back to Idaho Power’s grid. During the workshop, Idaho Power will share information on the
possible methods for evaluating the export credit rate. Participants can ask Idaho Power staff questions
during the workshop.
As a reminder, the IPUC granted legacy status to existing Schedule 6 and 8 (residential and small general
service) on-site generation systems as of December 20, 2019. Existing Schedule 84 (commercial,
industrial and irrigation) systems received legacy status as of December 1, 2020. Customers who do not
have legacy systems are subject to changes to the on-site generation offering, including changes to the
billing structure and the value of the export credit. Customers are notified when applying that the value
of excess energy is subject to change.
To participate in the workshop, visit idahopower.webex.com at 6 p.m. on May 2 and enter meeting
number 2592 303 2170 when prompted. At the next window, enter your name, e-mail address and the
password: VODER22. To participate over the phone, dial 1-650-479-3208 and enter meeting number
2592 303 2170 when prompted.
Idaho Power will accept informal written comments on the methods discussed for the export credit rate
for two weeks after the workshop. To submit comments, visit www.idahopower.com/cgworkshop or
email them to [e-mail].
About Idaho Power
Idaho Power, headquartered in vibrant and fast-growing Boise, Idaho, has been a locally operated
energy company since 1916. Today, it serves a 24,000-square-mile area in Idaho and Oregon.
The company’s goal to provide 100% clean energy by 2045 builds on its long history as a clean-energy
leader that provides reliable service at affordable prices. With 17 low-cost hydroelectric projects at the
core of its diverse energy mix, Idaho Power’s residential, business and agricultural customers pay among
the nation’s lowest prices for electricity. Its 2,000 employees proudly serve more than 600,000
customers with a culture of safety first, integrity always and respect for all.

Exhibit No. 1 Case No. IPC-E-22-22 G. Anderson, IPC
Page 1 of 2
IDACORP Inc. (NYSE: IDA), Idaho Power’s independent publicly traded parent company, is also
headquartered in Boise, Idaho. To learn more, visit idahopower.com or idacorpinc.com.
Jordan Rodriguez
Communications Specialist
[e-mail]
208-388-2460
Exhibit No. 1 Case No. IPC-E-22-22 G. Anderson, IPC
Page 2 of 2

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-22

IDAHO POWER COMPANY

ANDERSON, DI

TESTIMONY

EXHIBIT 2
Value of Distributed Energy Resources
Export Credit Rate Public Workshop
May 2, 2022
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 1 of 35
Introduction
Tim Tatum
Vice President
Regulatory Affairs
Jared Ellsworth
Transmission, Distribution &
Resource Planning Director
Connie Aschenbrenner
Senior Manager
Regulatory Affairs
Grant Anderson
Regulatory Consultant
Regulatory Affairs
Andrés Valdepeña Delgado
System Planning Engineer
Planning, Engineering, & Construction
Marc Patterson
Principal Engineer
Planning, Engineering, & Construction
2
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 2 of 35
Agenda
3
01
Regulatory Background
✓Commission-approved Study Framework
✓Highlight of Commission decisions
02
Avoided Energy
✓What is avoided energy?
✓Overview of price assumptions
03
Avoided Generation Capacity
✓What is avoided generation capacity?
✓Overview of methods
05 Wrap-up & Questions
✓Summary of components and time-variant ECR
✓Q&A session
04
Other Components
✓Transmission and distribution capacity, avoided line
loss, environmental benefits, and integration costs
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 3 of 35
How to Ask Questions
4
Select ‘All Panelists’
Select the Q&A
window
1 Select the raised hand icon to
notify panelists you would like
to ask a question
2
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 4 of 35
Request for Feedback
5
For more information visit
idahopower.com/cgworkshop
Send informal written comments to
[e-mail]
Please submit comments by
Monday, May 16, 2022
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 5 of 35
Regulatory Background
December 20, 2019
‒IPUC rejected settlement agreement that would have modified compensation
structure for customer-generators
‒IPUC grandfathered, or provided legacy status, to existing residential and small general
on-site generation systems
December 1, 2020
‒IPUC provided legacy status to existing commercial, industrial, and irrigation systems
6
Customers with legacy systems are not subject to changes in the on-site generation offering, including changes to
the compensation structure and value of the export credit rate, until legacy status terminates in 2045
01
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 6 of 35
Regulatory Background 01
June 28, 2021
‒Idaho Power filed to initiate the multi-phase process for a comprehensive study
of the costs and benefits of on-site generation as directed in Order No. 34046 as
outlined by the Idaho Public Utility Commission (“IPUC”) in Case No. IPC-E-18-15.
December 30, 2021
‒IPUC approved the Study Framework in Order No. 35284.
‒Idaho Power was ordered to complete the study in 2022, as soon as feasible.
7
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 7 of 35
Highlight of Commission Decisions
8
Export Credit Rate Value: The ECR should be based on a dollar value per kilowatt-hour (“kWh”) and not a
kWh credit.
Non-Firm Energy: The ECR must reflect that the energy received from on-site generators is currently non-firm.
Energy Pricing Inputs:Calculations and documentation for the value of exported energy should use energy
price assumptions consistent with Integrated Resource Planning (“IRP”)model inputs and market index price
assumptions.
Peak-Hour Pricing: It would be most appropriate to evaluate peak-hour pricing or another variable pricing
mechanism so customers who invest in storage can realize the value when they export stored energy.
Export Credit Rate Costs & Benefits:The study should include an evaluation of all benefits and costs that are
quantifiable, measurable, and avoided costs that affect rates.
Commission Order No. 35284
Source: 20211230Final_Order_No_35284.pdf (idaho.gov)
01
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 8 of 35
Tonight’s workshop will specifically focus
on methods that Idaho Power has
identified for the ECR components
Regulatory Background
1)Measurement Interval
2)Export Credit Rate (“ECR”)
3)Recovering Export Credit Rate Expenditures
4)Cost-of-Service & Rate Design
5)Project Eligibility Cap
6)Implementation Issues
9
Study Framework
01
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 9 of 35
Export Credit Rate Components to Study
10
01
Avoided
Generation
Capacity
Avoided
Energy
Avoided
Line
Losses
Avoided
Environmental
Costs
Integration
Costs
Avoided
Transmission
Capacity
Avoided
Distribution
Capacity
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 10 of 35
Avoided Energy 02
11
Energy Generated
10 kWh
Customer Exports
10 kWh
11
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 11 of 35
Avoided Energy
12
What is avoided
energy?
‒When a customer-generator exports a kilowatt-hour to the grid,
Idaho Power can produce or purchase less energy.
‒As a result, Idaho Power avoids the cost of producing or purchasing
that kilowatt-hour.
What price
assumptions are
used to value
avoided energy?
‒Forecasted Price: The marginal price forecast in Idaho Power’s
Integrated Resource Plan (“IRP”) model inputs.
‒Historical Price: Index prices for energy sold in day-ahead and real-
time energy markets.
02
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 12 of 35
Avoided Energy
13
Forecasted Energy Prices Historical Energy Prices
Integrated Resource Plan Market Index
‒Hourly market price derived
from the Aurora model
‒Market prices specifically
output from the 2021 IRP
preferred portfolio
‒Intercontinental Exchange (ICE)
is a regulated global futures
exchange
‒Day-ahead settled power prices
for the Pacific Northwest Mid-
Columbia (Mid-C) trading hub
‒Access to ICE Mid-C pricing
requires a subscription
‒A real-time market designed to
balance fluctuations in energy
supply and demand
‒Hourly weighted average price
of all Idaho Power points in the
Energy Imbalance Market
‒Pricing is publicly available
IRP Energy Price Inputs ICE Mid-C Index Energy Imbalance Market 1 2 3
02
Resources:
Our 20-Year Plan -Idaho Power
ICE Report Center -Data (theice.com)
California ISO -Prices, Today's Outlook (caiso.com)
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 13 of 35
Export Credit Rate Components to Study
14
03
Avoided
Generation
Capacity
Avoided
Energy
Avoided
Line
Losses
Avoided
Environmental
Costs
Integration
Costs
Avoided
Transmission
Capacity
Avoided
Distribution
Capacity
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 14 of 35
Avoided Generation Capacity
15
Potential to avoid additional generation resources
Addition of customer-generator exports 03
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 15 of 35
16
Avoided Generation Capacity
What is avoided
generation capacity?
‒When a customer exports a kilowatt-hour to the grid, it may delay
or defer Idaho Power’s need to build additional peak resources.
‒Avoided generation is dependent upon when the exported
kilowatt-hour occurs.
How is avoided
generation capacity
valued?
‒Contribution to Capacity: Idaho Power first compares the
contribution of customer-generator exports to a peak resource.
‒Cost of Capacity: The contribution is then compared to the cost to
otherwise build or procure the additional peak capacity.
03
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 16 of 35
Avoided Generation Capacity
17
Avoided Generation
Capacity Value
Cost of
Capacity
Cost of alternative, or
surrogate, peak resource
Capacity
Contribution
From NREL or
LOLE method
Energy Exported by
Customer-Owned Generators
National Renewable Energy Laboratory (“NREL”)
Loss of Load Expectation (“LOLE”)
03
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 17 of 35
Avoided Generation Capacity
18
03
How is contribution to capacity measured?
Top 100 Hours (NREL)1 Loss of Load Expectation (LOLE)2
✓Method used in Idaho Power’s 2019 Integrated
Resource Plan
✓Annual hourly method developed by NREL for
their capacity expansion model
✓Uses the top-100 net load hours as a proxy for
the hours of highest risk
✓Limited capability on handling storage
✓Simplified approach to LOLE
✓Method used in Idaho Power’s 2021 Integrated
Resource Plan
✓Reliability metric; improvement from NREL Top
100 Hour method
✓Industry standard to calculate capacity
contribution
✓Suitable to handle energy storage
Resources:
Our 20-Year Plan -Idaho Power
8760-Based Method for Representing Variable Generation Capacity Value : Preprint (nrel.gov)
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 18 of 35
Export Credit Rate Components to Study
19
04
Avoided
Generation
Capacity
Avoided
Energy
Avoided
Line
Losses
Avoided
Environmental
Costs
Integration
Costs
Avoided
Transmission
Capacity
Avoided
Distribution
Capacity
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 19 of 35
Avoided Transmission and Distribution Capacity
20
Available distribution capacity
Potential to avoid additional distribution capacity
Addition of customer-generator exports
Limited distribution capacity
04
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 20 of 35
Avoided Transmission & Distribution Capacity
What is avoided
transmission and
distribution capacity?
‒When a customer exports a kilowatt-hour to the grid, that
energy may delay or defer its need to build additional capacity.
‒Avoided transmission and distribution capacity is dependent upon
both when and where the customer exports occur.
How is avoided
transmission and
distribution capacity
valued?
‒Compare the contribution of customer-generator exports at the
localized peak capacity needs.
‒The contribution is then evaluated against the localized growth to
determine how long specific capacity projects may be delayed.
04
2121
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 21 of 35
Avoided Transmission & Distribution Capacity 04
22
How is it valued?
✓Evaluate actual and planned capacity projects
✓Compare exported energy at the specific time
and location to meet the peak capacity needs
for transmission and distribution capacity
✓For locations with export contributions that
exceed the peak capacity need, the
respective project may be deferred
✓Determine length of time a project can be
deferred based on load growth in the area
How is it measured?
Deferral
Value
Energy Exported by
Customer-Owned
Generators
Avoided Transmission
or Distribution
Capacity Value
22
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 22 of 35
Export Credit Rate Components to Study
23
04
Avoided
Generation
Capacity
Avoided
Energy
Avoided
Line
Losses
Avoided
Environmental
Costs
Integration
Costs
Avoided
Transmission
Capacity
Avoided
Distribution
Capacity
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 23 of 35
Avoided Line Losses 04
24
106
kWh
100
kWh
When energy is exported by a customer-generator, Idaho
Power avoids the energy and the associated line loss.
24
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 24 of 35
Avoided Line Losses 04
25
What are avoided
line losses?
‒When a customer exports a kilowatt-hour to the grid, that
energy could reduce losses in the distribution system.
‒Avoided line losses are dependent upon both when and where the
customer exports occur.
How are avoided line
losses valued?
‒Losses avoided during peak load times can be valued similar to
how avoided capacity is valued
‒Losses avoided during off-peak hours can be valued similar to how
avoided energy is valued.
25
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 25 of 35
Export Credit Rate Components to Study
26
04
Avoided
Generation
Capacity
Avoided
Energy
Avoided
Line
Losses
Avoided
Environmental
Costs
Integration
Costs
Avoided
Transmission
Capacity
Avoided
Distribution
Capacity
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 26 of 35
Avoided Environmental Costs 04
27
What are
environmental
benefits?
‒When a customer exports a kilowatt-hour to the grid, that
energy could avoid environmental-related costs.
‒Avoided environmental costs are dependent upon avoiding costs
that currently affect rates.
How are avoided
environmental costs
valued?
‒If there are quantifiable environmental costs that could be avoided
and reduce costs to provide utility service, Idaho Power would
credit customer-generators for that energy exported.
27
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 27 of 35
Export Credit Rate Components to Study
28
04
Avoided
Generation
Capacity
Avoided
Energy
Avoided
Line
Losses
Avoided
Environmental
Costs
Integration
Costs
Avoided
Transmission
Capacity
Avoided
Distribution
Capacity
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 28 of 35
Integration Costs
Illustrative Example –24 Hour Solar Output
29
04
1-Hour Average
1-Minute Average
Morning –Mid-Day Evening –Night
Time of Day
So
l
a
r

G
e
n
e
r
a
t
i
o
n

(
k
i
l
o
w
a
t
t
-ho
u
r
s
)
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 29 of 35
Integration Costs 04
30
What are integration
costs?
‒Idaho Power must plan for inconsistent production from variable
resources (e.g., solar and wind).
‒Integration costs reflect the incremental costs associated with
accommodating variable resources on the system.
How are integration
costs valued?
‒Idaho Power periodically conducts studies based on the amount of
variable resources on its system.
‒The most recent study completed in 2020 and reflected the
current level of intermittent generation on the system, and
it determined the costs to integrate additional variable resources.
30
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 30 of 35
Summary of Export Credit Rate Components 05
Avoided Energy
Avoided Generation Capacity
Avoided Transmission Capacity
Avoided Distribution Capacity
Avoided Line Losses
Avoided Environmental Costs
Integration Costs
Total Export Credit Value
31
Avoided
Generation
Capacity
Avoided
Energy
Avoided
Line
Losses
Avoided
Environmental
Costs
Integration
Costs
Avoided
Transmission
Capacity
Avoided
Distribution
Capacity
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 31 of 35
Export Credit Rate Structure
Illustrative Examples
32
05
Flat Export Credit Rate1
Seasonal Time-Variant Export Credit Rate2
Summer
AM PM
Non-Summer
AM PM
Summer Off-Peak Off-
Peak
Summer On-
Peak
AM PM
Non-Summer Off-Peak
AM PM
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 32 of 35
How to Ask Questions
33
Select ‘All Panelists’
Select the Q&A
window
1 Select the raised hand icon to
notify panelists you would like
to ask a question
2
05
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 33 of 35
Request for Feedback
34
For more information visit
idahopower.com/cgworkshop
Send informal written comments to
[e-mail]
Please submit comments by
Monday, May 16, 2022
05
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 34 of 35
35
Exhibit No. 2 Case No. IPC-E-22-22 G. Anderson, IPC Page 35 of 35

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-22

IDAHO POWER COMPANY

ANDERSON, DI

TESTIMONY

EXHIBIT 3
1
From:
Sent:Monday, May 2, 2022 6:56 PM
To:CGWorkshop
Subject:[EXTERNAL]Customer Generation Workshop
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify 
the sender before proceeding, and check for additional warning messages below. 
Thank you for hosting the customer generation ECR workshop. That was a ton of information in less than an hour. Do 
you have any information you can share, beyond the PPT, that I can review? I'm interested in the data and information 
that supports the benefits and costs you presented. If possible to also share the 2020 integration costs report that would 
be great (save me from navigating the PUC website). 

Thank you, 

Exhibit No. 3
Case No. IPC-E-22-22 G. Anderson, IPC
Page 1 of 12
1
From:
Sent:Monday, May 2, 2022 7:06 PM
To:CGWorkshop
Subject:[EXTERNAL]net metering
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify 
the sender before proceeding, and check for additional warning messages below. 
‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ 

I tried to attend the WEBEX virtual meeting on May 2 at 6 PM. 
Unfortunately something went wrong and I was not connected to the meeting. It is regretful that Idaho Power is still 
seeking to reduce the incentive for net metering through distributive solar power. I invested my own money as a teacher 
from the bottom ranking of educators pay in the USA. My family sacrificed other expenditures so we could invest in 
clean solar energy in order to do our part of reducing the use of fossil fuels through my power company. I started in 
2013, long before there was a public commitment by Idaho Power to reduce and eventually eliminate its worst fuel 
source, COAL. We accepted solar expenses and benefits to meet the challenge for a sustainable world for our children. 
In my family's case, it includes our 5 grandchildren and 2 great grandchildren. We must do the same for any IPC 
customers who are willing to make similar financial sacrifices and expect the same financial rewards. KEEP THE RATES 
THE SAME! 

I do not want any changes in the rate schedule for solar net metering customers past, present or future. 
The costs to Idaho Power are negligible because: 
1. My family absorbed the initial costs of the parts and labor to install our net metering solar panels, electrical upgrades 
and wiring, not IPC. 
2. During most of the year, our family's solar panels are adding electricity to neighboring homes since electricity flows 
like water to the nearest down grid from the source. So we do not use any of the high voltage power lines, substations 
and IPC resources to maintain those. However my family does pay for all of these in fixed rate expenses and monthly 
hookup for all the months that we send more electricity out than we consume. So we are paying for services we do not 
even receive for more than half of the months of connection. 
3. As a shareholder I am well aware of IPC's SEC reports of continually increasing sales and profit margins in spite of 
increasing solar net metering. Sooooooo net metering has not cost anything that has harmed our bottom line or shows 
any sign of affecting it. 

Benefits to keeping the rates as they are for grandfathered home solar net metering for all past, present and future solar 
net metering customers. 

1. The only way to get to NET‐ZERO carbon for IPC is through alternative energy. We are instrumental in helping IPC 
meet that goal but only if rates stay the same as those grandfathered homes. 
2. Solar is uniquely adaptable to the electrical high demands for the summer & as solar usage grows it helps with the 
higher demands and reduces the chances for the spot market expenses of buying electricity when demand exceeds 
capacity. 
3. IPC is privately owned and publicly controlled because we are a monopoly. There are two purposes to our existence. 
One purpose is to continue to return an investment profit. As solar energy decreases in cost, IPC is best suited to add its 
own solar generation and reduce its expenses with its growing net metering base. Second, IPC is a public utility that is 
mandated to work on behalf of the public by being a responsible corporate citizen. Fighting climate change is the 
number one challenge this century. We have to do everything possible and KEEPING RATES THE SAME IT AN IMPORTANT 
PART OF THIS GOAL. 

Exhibit No. 3
Case No. IPC-E-22-22 G. Anderson, IPC
Page 2 of 12
2

"The greatest threat to our planet is the belief that someone else will save it," ‐ — Robert Swan, Arctic explorer and 
climate activist 

Exhibit No. 3
Case No. IPC-E-22-22 G. Anderson, IPC
Page 3 of 12
1
From:
Sent:Tuesday, May 3, 2022 8:33 AM
To:CGWorkshop
Subject:[EXTERNAL]My comments re solar power meeting of May 2, 2022
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify 
the sender before proceeding, and check for additional warning messages below. 
To whom it may concern, 

Please enter the following comments into the meeting record. 

While I don't know the details of the current rate structure, nor the proposed changes, that apply to homeowners with 
solar panels, I fully intend to buy a grid‐connected solar system soon, and thus have a great deal at stake in this 
question. 

I understand that Idaho Power wishes to reduce the amount they would pay to grid‐connected home solar‐generating 
customers, for excess power that would flow from one's solar array into the grid. I believe this would be unfair to said 
customers, and would slow the acquisition of home solar systems by Idaho Power customers. 

Customers who invest tens of thousands of dollars in a home solar array are reducing Idaho Power's need to invest in 
power generation‐‐they are manifestly helping Idaho Power meet its objective of providing electricity to the region. 
Thus, the relevant regulations should incentivize such weighty investments by homeowners, not penalize them. 

It is critically urgent that society make the transition to fully renewable energy generation as swiftly as possible‐‐clearly, 
the planet's wellbeing and human welfare are at stake. Making it less painful for homeowners to make such large 
investments in furtherance of a societal good is the right thing to do. 

Idaho Power, please be a good citizen and not a greedy one. 

Sincerely, 

Exhibit No. 3
Case No. IPC-E-22-22 G. Anderson, IPC
Page 4 of 12
1
From:
Sent:Tuesday, May 10, 2022 8:10 PM
To:CGWorkshop
Cc:[e-mail]
Subject:[EXTERNAL]Comments on the costs and benefits study for the export credit rate for residential solar
installations
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify 
the sender before proceeding, and check for additional warning messages below. 
Thank you for hosting the May 2 workshop at which you and your staff presented the plan for your
study of calculating the export credit rate for power generated by residential solar installations.

My comments are:
1. Every Idaho Power customer knows that Idaho Power does not like residential solar.
2. It is disingenuous for Idaho Power to try to discourage residential solar by attempting to reduce
credit for non-legacy on-site generation systems and then in the same breath say that you are
a company that cares about climate change impacts.
3. Your presentation was highly technical and difficult for the average person to understand which
leads one to the conclusion that your study will not result in a fair or equitable assessment of
the value of on-site generated solar. "Keep it technical to keep the comments to a minimum"
seemed to be the point of the presentation.
4. While I respect the Idaho Power staff and their engineering skills, I also understand their
"golden handcuffs" when responding to questions and designing the study on the value of
residential solar.
5. As an Idaho Power customer, locked into the system and without options, I expect honesty,
integrity, fairness, and unobscured/transparent evaluation in your study.
Best regards,

Exhibit No. 3
Case No. IPC-E-22-22 G. Anderson, IPC
Page 5 of 12
1
From:
Sent:Monday, May 23, 2022 2:11 PM
To:CGWorkshop
Subject:[EXTERNAL]Case IPC-E-21-21
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify
the sender before proceeding, and check for additional warning messages below.
Dear Idaho Power,
I’m writing to comment on Case No. IPC-E-21-21. I only recently heard of the proposed change, so I hope my comments
will be considered in this matter. At any rate I do hope the concerns I raise below can be addressed.
Reading the case, it seems the main rationale for moving away from the volumetric rate or one to one net metering
rests on the fixed costs of your operations. Two main points I ask you need to consider with regards to economic
efficiency:
1) Even residential customers who ‘zero out’ their power bill still pay a fee to stay connected to the grid. If the
rate case is truly about fixed costs, then you should adjust this fixed monthly cost and not the per-unit cost of
power returned to the grid under net metering.

2) A major fixed cost for Idaho Power is investing in the facilities which generate power. The more customers
who are generating power on your behalf, the fewer investments Idaho Power needs to make, thus saving you
substantial fixed costs. Coupled with the fact that solar power produces
more power (for air conditioning and irrigation, for example), this increase in production saves Idaho Power
from having to directly invest in summer surge capacity.
I do hope you can address this in your eventual st
possible. Thank you for your time.
Best Regards,

Idaho State Uni

Exhibit No. 3
Case No. IPC-E-22-22 G. Anderson, IPC
Page 6 of 12

1

May 16, 2022

Reference: May 2, 2022 WebEx workshop

Subject: Additional comments of Clean Energy Opportunities for Idaho (CEO)

CEO recognizes the magnitude of the Study Idaho Power is preparing regarding the cost,
benefits and compensation of excess energy from customers with on-site generation. CEO
appreciates Idaho Power having held the workshop on May 2nd. Both this Study and the
Company’s extensive proposals related to the proposed Clean Energy Your Way programs are
welcome responses to the rapidly changing environment that electric utilities like Idaho Power
serve.

While much valuable information was provided during the May 2nd workshop, the format of
submitting questions/comments via a text chat feature was inherently limiting. Thank you for
accepting additional input in this alternative fashion. CEO offers comments on four topics that
we see as potentially adding to the efficacy of the Study.

1. Exports from customers with renewable on-site generation have valuable
environmental characteristics. Failure to recognize the potential for such exports to
allow Idaho Power to avoid the costs associated with purchasing additional RECs would
unfairly bias the Study results.

2. The study should consider an alternative method for harnessing the location value of
self-generator exports at certain advantageous locations within the Company’s
distribution system.

3. Time-of-Use (TOU) rates would be better focused on incenting changes in consumption
patterns than in approximating variations in the marginal value of exports based on the
timing of the export event.

4. The Study should address the value of exports from customers with on-site generation
in reducing the fuel price risk all customers face as a result of current prices for natural
gas being dramatically higher than were projected in either the 2019 or 2021 IRP.

Exhibit No. 3
Case No. IPC-E-22-22 G. Anderson, IPC
Page 7 of 12

2

1 Exports from customers with renewable on-site generation have valuable
environmental characteristics. Failure to recognize the potential for such exports to
allow Idaho Power to avoid the costs associated with purchasing additional RECs
would unfairly bias the Study results.

RECs are not the only way to certify to customers that they are paying for clean energy. While
some business customers’ ESG goals may require the purchase of RECs as the specific form of
certified renewable energy to meet their goals, many other customers could find exports from
customers with renewable self-generation perfectly adequate.

If we heard correctly, CEO believes that Jared Ellsworth indicated during the workshop that the
sole source of avoided cost the Company was considering for environmental characteristics was
from reductions in payments under pollution regulations. CEO believes that approach would
unfairly bias too low the analyzed value of avoided environmental costs.1

It has been noted in a separate docket that within the CEYW - Flexible program, more
customers have expressed a desire to purchase clean energy than the Company currently has
adequate RECs to serve. CEO believes exports from customers with renewable self-generation
should be allowed to serve as a source of clean power CEYW customers wish to purchase.

CEO sees the Company’s billing system is adequate to ensure reliable recording of such sales
transactions. Further, CEO believes that the Company could require, as one of the terms
related to exported energy, that the Company acquire all the environmental characteristics of
the exported energy.

For these reasons, CEO believes the Study evaluation of Environmental Benefits associated with
self-generating customer exports should include their value for avoiding costs to otherwise
purchase RECs for “Green Power” or CEYW type programs.2

2 The study should consider an alternative method for harnessing the location value of
self-generator exports at certain advantageous locations within the Company’s
distribution system.

1 “We have not been granted the legislative or executive authority to monetize many of the environmental
attributes addressed by Parties and customers. That said, there are environmental considerations that are
quantifiable and will be included in an ultimate determination of fair, just and reasonable terms for the Company’s
on-site generation program. The intent of these studies is to value the export to the Company’s system.” Order
35284, page 12 2 Under the heading “Environmental and Other Benefits”, the Commission stated “The Commission finds it
reasonable that the Study include an evaluation of all benefits and costs that are quantifiable, measurable, and
avoided costs that affect rates.” Order 35284, page 27
Exhibit No. 3
Case No. IPC-E-22-22 G. Anderson, IPC
Page 8 of 12

3

The Commission has recognized the potential for self-generation customers to avoid costs
based on the location of the customers’ exports.

“Avoided distribution costs are locational benefits properly studied.”3
That said, allocating those benefits via customer specific locational pricing is not currently
feasible and non-site specific pricing is unlikely to incent customer installations of self-
generation that could avoid future distribution system upgrade costs.

CEO believes the Study should evaluate whether an alternative method is possible for
harnessing the potential for increased customers’ generation at some specific locations to avoid
distribution system upgrade costs. Specifically, CEO requests that the Study evaluate whether
the Company could provide incentives to reduce the cost for customers to install self-
generation in locations within the distribution system where such self-generation could avoid
future costs associated with distribution system upgrades. CEO believes it would be
appropriate for the dollar amounts associated with those incentives to go into a regulatory
asset upon which the Company could earn a return.

3 Time-of-Use (TOU) rates would be better focused on incenting changes in
consumption patterns than in approximating variations in the marginal value of
exports based on the timing of the export event.

In the context of multiple related dockets, CEO perceives opportunities for using price signals to
incent changes in consumption patterns and generally applauds the Company’s consideration
of TOU rates. However, CEO believes that TOU rate structures should be focused on changes to
consumption patterns, which requires allowing self-generators access to time differentiated
rates for consumption.

In IPC-E-21-41 the Company recognizes the need for substantial resource additions (many of
which are likely to be solar generation) in the immediate future to address imminent
generation capacity shortfalls in meeting late summer afternoon and early evening loads. In
IPC-E-22-13 the Company requests certification of the need to purchase batteries, in part to
allow time-shifting of that solar generation to meet those late afternoon, early evening loads.

Using TOU price signals for consumption makes great sense to move load from times of high
marginal cost to serve to times with lower marginal costs. Currently, the periods with high
marginal costs warranting a higher TOU price, largely result from a need to add load-serving
capacity to meet rising late summer afternoon and early evening loads. Similarly, there are
periods of lower than average marginal prices. As is displayed in the graph below, solar output
3 Order 35284, page 19
Exhibit No. 3
Case No. IPC-E-22-22 G. Anderson, IPC
Page 9 of 12

4

rises faster than load during a mid-day (say 10am-4pm) period. Using price signals to move
some load from the high use periods (summer 5-10pm) where rising loads are requiring
incremental investment to low marginal cost periods where some investment in batteries for
time-shifting could be offset makes good economic sense.

CEO believes the asymmetrical proposal of higher TOU rates for exports only and in summer
peak periods is too narrow. For example, an EV driver and self-generator coming home for
work has no price signal to choose between charging the car at 6pm vs. at night. TOU rate
changes should include allowing Schedule 6 & 8 customers access to time-differentiated rates
for consumption, and both higher rates in high cost periods and lower rates in low cost times.
As CEO detailed in comments made in IPC-E-21-404, there are other sources of marginal
avoided cost information than the TOU proposal mentioned at the workshop.

This chart shows the rate at which loads change by hour during the four seasons. Note that in
Winter, Spring and Fall, loads fall during the 10am-4pm peak solar output period. Even in the
Summer, although loads rise during the 10am-4pm period, solar output rises faster thus
allowing more load to be served during that period at a very low marginal cost. Of course,
loads fall in the night in all seasons but solar can’t directly affect those opportunities.

4 See IPC-E-21-40, CEO comments dated May 12, 2022, page 7
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Exhibit No. 3
Case No. IPC-E-22-22 G. Anderson, IPC
Page 10 of 12

5

4 The Study should address the value of exports from customers with on-site generation
in reducing the fuel price risk all customers face as a result of current prices for natural
gas being dramatically higher than were projected in either the 2019 or 2021 IRP.

It is possible to read some ambiguity in the directions the Commission provided the Company
regarding the data sources used for valuing customer exports. For example, the Commission
noted on page 9 of Order 35284:
“We remind the Company that the study must use the most current data possible, and
the data must be readily available to the public and in the Commission’s decision-making
record. Id. This does not specifically dictate use of either the 2019 or the 2021 Integrated
Resource Plan (“IRP”) for the study.”

While for purposes of calculating Avoided Energy values, the Commission said:
“Provide the calculations and documentation for the avoided cost of exported energy
using: (a) energy price assumptions in the Company’s most recently acknowledged IRP,
and (b) market index price assumptions”. Order 35284, page 14

The above graph shows that the “most recent data” (included in the Company’s current PCA
request under IPC-E-22-11) forecasts dramatically higher natural gas driven marginal costs than
the costs forecast in the 2021 IRP (IPC-E-21-43).
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Substantial differences exist between Mid-C prices in 2021 IRP and
non-PURPA Purchased Power prices in Apr22 -Mar23 PCA
Data sources:
Mid-C highest hour and monthly average -CEO Production Request #4 -Mid-C Energy Prices -IPC-E-21-43
Acct 555 non-PURPA Purchased Power -Brady direct, Ex #1 -IPC-E-22-11
Average monthly Mid-C price / MWh
Highest Mid-C WMh price during any hour that month
Apr22-Mar 23 PCA Non-PURPA Purchased Power monthly average price / MWh
Exhibit No. 3
Case No. IPC-E-22-22 G. Anderson, IPC
Page 11 of 12

6

The PCA submittal shows the Company projecting substantial power purchases in every month,
with an annual total of such purchases equaling about 10% of customer load (180 aMWs of
annual power purchases) at average monthly prices sometimes more than double the highest
price the 2021 IRP forecasted for any hour of that month.

CEO has previously expressed concerns regarding the use of 2019 IRP price data due to start-up
difficulties the Company experienced in its first use of a Capacity Expansion model.5 Clearly, a
comparison of the price data in IPC-E-22-11 with that the 2021 IRP shows prices from the 2021
IRP are grossly outdated.

Even if the Company believes Commission direction requires that they calculate avoided energy
costs based on IRP price data, CEO believes the Study must address the potential for exports to
reduce exposure for all customers by mitigating fuel price risk.6 In addition to evaluating an
ECR using 2021 IRP data, CEO asks that the study also evaluate the ECR using the price data in
IPC-E-22-11.

Much like the verification testing IPC conducts in running multiple scenarios during the IRP
process, this comparison of ECR values would indicate whether there are material differences
between the 2021 IRP data and more current market conditions.

Respectfully submitted,

Mike Heckler
Policy Director
Clean Energy Opportunities for Idaho

5 IPC-E-21-21, CEO comments dated November 16, 2021, page 5 6 See Section 10-Avoided risk, Order 35284 page 22
Exhibit No. 3
Case No. IPC-E-22-22 G. Anderson, IPC
Page 12 of 12