20230501Direct Anderson with Exhibits.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF IDAHO POWER
COMPANY’S APPLICATION FOR
AUTHORITY TO IMPLEMENT CHANGES TO
THE COMPENSATION STRUCTURE
APPLICABLE TO CUSTOMER ON-SITE
GENERATION UNDER SCHEDULES 6, 8,
AND 84 AND TO ESTABLISH AN EXPORT
CREDIT RATE METHODOLOGY

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CASE NO. IPC-E-23-14

IDAHO POWER COMPANY

DIRECT TESTIMONY

OF

GRANT T. ANDERSON
RECEIVED
2023 May 1, 4:44PM
IDAHO PUBLIC
UTILITIES COMMISSION

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
Q. How is your testimony organized? 4
A. My testimony begins with an overview of the 5
Company’s modified project eligibility cap proposal for all non-6
legacy on-site customer generation systems. Next, I will provide 7
an overview of the customer bill impact from the proposed change 8
in the compensation structure. I will then address the Company’s 9
proposal for other implementation considerations, including 10
recovery of export credit expenditures, billing and transfer 11
criteria for net billing financial credits, conversion of 12
accumulated kilowatt-hour (“kWh”) credits to financial credits 13
for customers with non-legacy systems, and customer education 14
and outreach. I also address the Company’s proposed tariff 15
revisions related to the net billing compensation structure and 16
interconnection requirements for systems under a modified 17
project eligibility cap. Last, I will describe the Company’s 18
proposed annual Export Credit Rate (“ECR”) update schedule. 19
Q. Have you prepared any exhibits? 20
A. Yes. My testimony incudes Exhibit Nos. 6 - 8, which 21
calculate the bill impact for non-legacy customer generators for 22
the twelve months ending December 31, 2022, for residential, 23
small commercial, and large commercial, respectively. 24
// 25

ANDERSON, DI 4
Idaho Power Company
I. PROJECT ELIGIBILTY CAP 1
Q. What is the current project eligibility cap for 2
Idaho Power customer-generators? 3
A. The current project eligibility cap varies by 4
customer class. Schedule 6, Residential Service On-Site 5
Generation (“Schedule 6”) and Schedule 8, Small General Service 6
On-Site Generation (“Schedule 8”) applicability defines the 7
current project eligibility cap with a total nameplate capacity 8
rating of 25 kilowatts (“kW”). Schedule 84, Customer Energy 9
Production Net Metering Service (“Schedule 84”) is applicable to 10
Schedule 9, Large General Service (“Schedule 9”), Schedule 19, 11
Large Power Service (“Schedule 19”), and Schedule 24, 12
Agricultural Irrigation Service (“Schedule 24”) customers. 13
Schedule 84 defines the current project eligibility cap for 14
customers under Schedule 9, 19, and 24, with a total nameplate 15
capacity rating of 100 kW. 16
Q. What information did the Company consider in 17
evaluating the appropriateness of the existing cap for Schedule 18
6 and 8 non-legacy systems? 19
A. The Company evaluated the potential output from 20
installing rooftop solar up to 25 kW for a residential customer. 21
A 25 kW system could generate approximately 37,000 kWh per year1 22
– equating to around 3,100 kWh per month. In comparison, the 23
average residential customer uses about 930 kWh per month, or 24

1 Assumes a capacity factor of 17 percent.

ANDERSON, DI 5
Idaho Power Company
less than one-third of the energy a 25 kW system is expected to 1
produce on average. Relative to the 25 kW cap, the average 2
residential customer service point maximum annual hourly demand 3
is approximately 6-7 kW. Additionally, the most commonly 4
installed residential system is about 7.5 kW, or 30 percent of 5
the 25 kW cap. 6
Q. Based on its analysis, is the Company proposing to 7
modify the project eligibility cap for exporting systems under 8
Schedules 6 and 8? 9
A. No. The data suggests the current cap is not 10
limiting for residential and small general service customers and 11
the Company believes the 25 kW cap continues to be reasonable 12
for the administration of interconnection for service under 13
Schedules 6 and 8. 14
Q. What information did the Company rely on to 15
evaluate whether the Schedule 84 cap continues to be reasonable? 16
A. The intent of net metering is to offset one’s 17
energy usage behind the meter. Therefore, the Company evaluated 18
electrical demand by service point for non-solar commercial, 19
industrial, and irrigation (“CI&I”) service points. 20
Figure 1 is a histogram for all non-solar CI&I service 21
points by annual demand. Figures 9.2 and 9.3 in the October 2022 22
// 23

ANDERSON, DI 6
Idaho Power Company
VODER Study2 provide a more detailed breakdown of this same data 1
by service point between commercial/industrial and irrigation 2
customer service points. 3
Figure 1 4
Non-Solar Commercial, Industrial, and Irrigation Service Point 5
Histogram 6
7 8
Q. In your opinion, what are the key takeaways from 9
this figure? 10
A. Generally, the cap is not limiting to the majority 11
of customers at a given service point. Approximately six percent 12
of CI&I service points registered an annual demand over 100 kW, 13
with the remaining 94 percent registering a demand of 100 kW or 14
less. While it may not appear to be limiting for the majority of 15

2 See Attachment 1. See also, In the Matter of Idaho Power Company’s
Application to Complete the Study Review Phase of the Comprehensive Study of
Costs and Benefits of On-Site Customer Generation & For Authority to
Implement Changes to Schedules 6, 8, and 84, Case No. IPC-E-22-22, Attachment
1 (October 2022 VODER Study) to Idaho Power Company’s Final Comments (Oct.
26, 2022).
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Annual Peak Demand (kW)

ANDERSON, DI 7
Idaho Power Company
customers, in the Company’s experience customers who have some 1
of those larger service point demands desire to install larger 2
on-site generation systems. Rather than installing a system 3
sized commensurate with their demand at a given site, those 4
customers have had to rely on the Company’s existing “meter 5
aggregation rules” by installing smaller, disaggregated 100 kW 6
systems. Those customers then apply annually to transfer kWh 7
credits to qualifying service points. 8
Q. Based on its analysis, is the Company proposing to 9
modify the project eligibility cap for Schedule 84? 10
A. Yes. The Company proposes that the project 11
eligibility cap for Schedule 84 be set at the greater of 100 kW 12
or 100 percent of demand at the service point. 13
Q. Please describe the relationship between customer 14
and service point as it relates to administration of Idaho 15
Power’s tariff. 16
A. Often, the Company will refer to “customer” and 17
“service point” synonymously when discussing a request for 18
service. Each of Idaho Power’s service schedules in its tariff – 19
including the on-site generation schedules – are administered 20
according to service point. A service point is akin to the point 21
of delivery which is often the Company’s meter. 22
Q. Did the Company consider a proposal that would have 23
measured aggregate demand at a customer level versus service 24
point? 25

ANDERSON, DI 8
Idaho Power Company
A. Yes. The Company considered aggregating demand by 1
customer rather than service point but did not find that to be a 2
feasible approach. 3
As I previously noted, the Company does not administer 4
any of its tariff schedules based on aggregated service point 5
data and the Company is concerned that introducing that 6
requirement for the purpose of determining certain criteria only 7
applicable to its on-site generation service schedules would 8
lead to a burdensome administrative process that could be prone 9
to error. 10
Decoupling the project eligibility cap from the service 11
point will also create the potential for over-sized systems that 12
could lead to distribution circuit upgrades solely to support 13
on-site generation. While the on-site generation customer would 14
be responsible for the initial cost of the upgrades, the ongoing 15
cost, including maintenance, replacement, property taxes, and 16
other ancillary costs will become the responsibility of the 17
Company. These costs are collectively paid for by all customers. 18
Q. How does the Company propose to measure demand for 19
purposes of administering the cap? 20
A. For customers with at least 12 months of historical 21
billing data, the Company proposes using the maximum billing 22
demand from the last 12 months, measured when the customer 23
generation application is submitted - to establish a project 24
eligibility cap. 25

ANDERSON, DI 9
Idaho Power Company
For new customers, or those without at least 12 months of 1
historical billing, the Company has identified a few methods for 2
determining demand, depending on the circumstances. In the first 3
instance, the Company will evaluate and rely on available 4
historical billing data at that service location. For example, 5
if a new customer assumes service at a service point that has 6
historical usage, that historical usage could be relied upon. In 7
the absence of that information, or in the case where a new 8
customer believes their demand will exceed that of a past 9
customer, the Company proposes requiring an analysis of the 10
facility’s power needs performed by a professional engineer. 11
For irrigation customers without a full in-season billing 12
history, a conversion factor related to the horsepower of their 13
pump(s) at the service point would determine the maximum demand. 14
Q. Has the Company considered how it would administer 15
a situation where a customer’s demand decreases after the 16
initial installation? 17
A. Yes. The Company plans to determine the cap for the 18
service point at the time of application. If the customer demand 19
at the service point later decreases or a new customer takes 20
over the premise with a lower power requirement, the Company 21
does not propose the Commission require a change or reduction in 22
the existing system size based on their new demand and power 23
needs. Not only would tracking and managing changes be 24
administratively burdensome, but it would have significant 25

ANDERSON, DI 10
Idaho Power Company
impacts on the customer – most of which would undoubtedly be 1
costly and would likely result in confusion and frustration. 2
Alternatively, if the customer’s demand increases and 3
they desire to interconnect a system expansion, this could be 4
conducted pursuant to the existing interconnection requirements 5
of Schedule 68, Interconnections to Customer Distributed Energy 6
Resources (“Schedule 68”) by applying for a system modification. 7
Q. Have other parties or customers taken a position on 8
the project eligibility cap in previous dockets? 9
A. Yes. Clean Energy Opportunities for Idaho (“CEO”) 10
filed a petition in Case No. IPC-E-22-12, which proposed setting 11
the project eligibility cap for Schedule 84 customers at 100 12
percent of demand. The Idaho Irrigation Pumpers Association 13
(“IIPA”) did not support a change to the cap until changes to 14
the compensation structure were approved by the Commission.3 In 15
context of discussing the project eligibility cap, the Idaho 16
Public Utility Commission Staff (“Staff”) acknowledged that 17
subsidies exist under the current net energy metering (“NEM”) 18
framework.4 Additionally, Staff stated that if the cap is 19
increased before an avoided-cost-based ECR is implemented, it 20
would result in more customer generation capacity being added 21
with additional cost shifts to non-generating customers.5 The 22

3 Case No. IPC-E-22-22, IIPA Comments at 8 (Sep. 21, 2022).
4 Case No. IPC-E-22-22, Staff Comments at 17 (Sep. 21, 2022).
5 Id.

ANDERSON, DI 11
Idaho Power Company
Company has also heard anecdotally from its irrigation customers 1
that a demand-based cap would be favorable. 2
Q. Does the Company believe its proposed modification 3
to the project eligibility cap for non-legacy systems addresses 4
concerns raised by customers and other stakeholders? 5
A. Yes. The Company believes this modification to the 6
cap contingent upon the concurrent replacement of the existing 7
NEM with a net billing compensation structure and an ECR based 8
on avoided cost appropriately considers stakeholder feedback and 9
will improve the service offering. 10
Q. Please explain whether the Company continues to 11
have the concerns it raised previously about modifying the 12
project eligibility cap under Schedule 84, and if not what has 13
changed? 14
A. It does; however, these concerns are generally 15
mitigated when evaluating all issues in this docket 16
simultaneously. The primary purpose of the cap was to mitigate 17
safety and reliability concerns. Mr. Jared Ellsworth’s testimony 18
addresses the requirements to ensure that all interconnected 19
systems do not compromise safety and reliability. An additional 20
rationale for the cap was to limit subsidies present as a result 21
of NEM. In this docket, the Company has proposed modifying the 22
measurement interval and ECR - the combination of which I will 23
generally refer to as “compensation structure.” The proposed 24
compensation structure will better align cost recovery with 25

ANDERSON, DI 12
Idaho Power Company
system utilization and compensation for excess energy with the 1
costs and values of those activities. For these reasons, the 2
Company proposes changes to both the compensation structure and 3
the project eligibility cap occur coincidentally. 4
Q. Would the Company support a modification to the 5
project eligibility cap under Schedule 84 absent a change to the 6
compensation structure? 7
A. No. For the reasons I just mentioned, the Company 8
believes the existing project eligibility cap mitigates some 9
cost-shifting under the current retail rate NEM compensation 10
structure. Therefore, the Company does not advocate changing the 11
project eligibility cap without an avoided-cost-based rate for 12
excess generation measured under a net billing compensation 13
structure. 14
Q. Is the Company proposing modifications to the 15
administration of how energy storage devices are applied to the 16
project eligibility cap? 17
A. Yes. The Company is aware of limited circumstances 18
where AC-coupled energy storage devices have resulted in a 19
customer’s proposed system to exceed the project eligibility 20
cap. The Company proposes to modify its administration of the 21
cap to only evaluate capacity of an energy storage device for 22
purposes of its Feasibility Review to continue to ensure the 23
interconnection does not impact safety or reliability of Idaho 24
Power’s system. However, for all future applications for 25

ANDERSON, DI 13
Idaho Power Company
interconnection, an energy storage device would not count 1
towards the capacity limits for applicability of exporting 2
systems under Schedule 6, 8, and 84.Q. Are there other items 3
that should be considered in relation to the Company’s proposed 4
modification to the project eligibility cap? 5
A. Yes. Mr. Ellsworth’s testimony includes more detail 6
about the interconnection requirements for customer-generators 7
and the considerations associated with modifying the project 8
eligibility cap for Schedule 84. 9
II. COMPENSATION STRUCTURE & BILL IMPACT 10
Q. Did the Company evaluate the impact on customer 11
bills that will result with the change to a real-time net 12
billing compensation structure? 13
A. Yes. Included with my testimony are Exhibit Nos. 6-14
8, which summarize the bill impact for non-legacy on-site 15
generation customers with billing data for the twelve months 16
ending December 31, 2022. 17
Q. Please provide an overview of the results of the 18
bill impact analysis. 19
A. There were approximately 3,750 non-legacy 20
residential customers taking service under Schedule 6 for the 21
twelve months ending December 31, 2022. Exhibit No. 6 summarizes 22
the bill impact calculations for non-legacy Schedule 6 service 23
points. The Company compared base rates under the existing NEM 24
and proposed real-time net billing compensation structure. On an 25

ANDERSON, DI 14
Idaho Power Company
average monthly basis, residential customer-generators monthly 1
bill under NEM was $39.63 and under real-time net billing 2
increased to $51.75, an average increase of $12.12 per month. 3
Approximately 50 percent of customers would experience an 4
average monthly bill increase less than $10 and 75 percent would 5
experience a bill increase less than $15 per month. 6
Figure 2 7
Average monthly bill for non-legacy residential customer-8
generators in 2022, by average net monthly energy use 9
10
Figure 2 separates the customer-generators by their 11
average monthly energy consumption in 2022 under a monthly 12
measurement interval. The residential customer-generators have 13
been grouped into six categories to evaluate the average 14
magnitude of bill impacts. Figure 2 does not account for the 15
residential customer-generators average monthly bill before 16
$5 $23
$62
$99
$137
$235
$12 $35
$76
$116
$156
$252
0 kWh
(642 customers)
1 ≤ 500 kWh
(2,123 customers)
500 ≤ 900 kWh
(563 customers)
900 ≤ 1,300 kWh
(197 customers)
1,300 ≤ 1,700 kWh
(110 customers)
1,700 kWh+
(119 customers)
Average Net Monthly kWh Delivered
NEM Net Billing

ANDERSON, DI 15
Idaho Power Company
solar was installed, which, all else held equal, would have been 1
higher than the real-time net billing average monthly bill.6 2
For the twelve months ending December 31, 2022, there 3
were 13 non-legacy small general service customers and 8 non-4
legacy large commercial service customers taking service under 5
Schedule 8 and Schedule 84, respectively. Exhibit Nos. 7 and 8 6
summarize a similar analysis for these customers. There were no 7
non-legacy irrigation customers taking service for the 8
respective 12-month period. 9
Q. Did the Company consider implementing a transition 10
period to mitigate customer impacts associated with a modified 11
ECR? 12
A. Yes. Ms. Aschenbrenner’s testimony addresses the 13
Company’s evaluation of a transition plan, which considered the 14
results of the bill impact analysis. 15
III. IMPLEMENTATION CONSIDERATIONS 16
Q. What implementation considerations and 17
recommendations are included in the Company’s proposal? 18
A. In Order No. 35631, the Commission stated that the 19
October 2022 VODER Study complied with its previous directives 20
and should serve as a basis for the Company’s implementation 21
recommendation in a subsequent case.7 Ms. Aschenbrenner’s 22
testimony addresses the Company’s proposal to utilize a real-23

6 Attachment 1 at 94-95, Figures 6.1 and 6.2.
7 Case No. IPC-E-22-22, Order No. 35631 at 28 (Dec. 19, 2022).

ANDERSON, DI 16
Idaho Power Company
time measurement interval for the compensation structure and Mr. 1
Ellsworth’s testimony addresses the methods the Company has 2
proposed for the valuation of the ECR. In this section, I will 3
address the following implementation considerations: (1) 4
recovery of ECR expenditures; (2) application of financial 5
credits for billing items and transfer criteria, (3) conversion 6
of accumulated kWh credits to financial credit, and (4) customer 7
education and outreach. 8
Q. Do these implementation considerations impact 9
customers with legacy systems? 10
A. No. The proposed on-site generation compensation 11
structure changes would only apply to customers with non-legacy 12
systems. As a result, customers with legacy systems will 13
continue to take service under the rules of NEM until legacy 14
status terminates. Therefore, these implementation 15
considerations do not impact customers with legacy systems. 16
Recovery of Export Credit Expenditures 17
Q. Please describe the Company’s recommendation 18
related to recovering export credit expenditures. 19
A. For customers with non-legacy systems, the Company 20
proposes to treat the ECR expenditures as a net power supply 21
expense (“NPSE”) subject to 100 percent recovery through the 22
Power Cost Adjustment (“PCA”), similar to the practice for 23
Public Utility Regulatory Policies Act of 1978 (“PURPA”) 24
Qualifying Facilities (“QF”). The October 2022 VODER Study 25

ANDERSON, DI 17
Idaho Power Company
evaluates recovering export credit expenditures in Section 8 1
(pages 115-117). 2
Q. Why is it appropriate to recover the cost of ECR 3
expenses through the PCA? 4
A. ECR expenses represent the cost of energy that the 5
Company is purchasing for the benefit of all of its customers. 6
Therefore, it is reasonable for all customers to pay for that 7
energy through the PCA. Prior to 2014, net metering customers 8
were compensated for their net excess generation through 9
financial credits, the cost of which were recovered through the 10
PCA.8 11
Q. Why is it appropriate that ECR expenditures be 12
recovered through the PCA at 100 percent not subject to the 95 13
percent/5 percent sharing mechanism? 14
A. The Energy Policy Act of 2005 amended Section 111 15
of PURPA by adding five new federal ratemaking standards for 16
electric utilities. Notably, however, many of the basic concepts 17
embodied in the “new” federal standards were not new in Idaho. 18
For example, in considering the amendments to PURPA the 19
Commission concluded that the federal net metering standard, 20
which required electric utilities to make available upon request 21
a service offering under which a customer could offset their 22

8 In the Matter of the Application of Idaho Power Company for Authority to
Implement a Power Cost Adjustment (PCA) Rate for Electric Service from May
16, 2003 through May 15, 2004, Case No. IPC-E-03-05, Exhibit No. 3 to Direct
Testimony of Gregory W. Said (Apr. 15, 2003).

ANDERSON, DI 18
Idaho Power Company
energy usage with their own generation, had already been 1
implemented in Idaho.9 Regardless, similar to resources a utility 2
is forced to acquire under federal law, which the Commission has 3
allowed the Company 100 percent recovery of since the PCA was 4
established in 1983,10 customer-generator exports have become a 5
must-take resource at the state level and as such 100 percent of 6
ECR expenditures should be recovered through the PCA. In all 7
other instances where the Company is required to make payments 8
at prices consistent with Commission order, such as demand 9
response and PURPA, those payments are recovered at 100 percent. 10
Financial Credits – Billing and Transfer Criteria 11
Q. Please describe the Company’s recommendation for 12
how it proposes to apply financial credits to the bill. 13
A. The Company proposes that financial credits offset 14
all billing components of the bill – not just the energy-related 15
portion of a customer bill. 16
Q. Does the Company propose that financial credits 17
could be transferred to other meters or service points? 18
A. Yes, for customers with non-legacy systems the 19
Company proposes that a customer could transfer financial 20
credits to another account held in their name for their own 21

9 In the Matter of the Commission’s Consideration of the Five Amendments to
Section 111 of PURPA Contained in the Energy Policy Act of 2005, Case No.
GNR-E-06-02, Order No. 30229 at 3-5 (Jan. 24, 2007).
10 In the Matter of the Application of Idaho Power Company for Authority to
Implement a Power Cost Adjustment Tariff for Electric Service to Customers in
the State of Idaho and for Approval of New Rates for Service Under the FMC
Special Contract, Case No. IPC-E-92-25, Order No. 24806 at 17 (Mar. 29,
1993).

ANDERSON, DI 19
Idaho Power Company
usage. Financial credits would be non-transferrable in the event 1
the customer relocates and/or discontinues service at the point 2
of delivery associated with the exporting system. Any unused 3
financial credit from discontinued service would be absorbed to 4
the benefit of customers through a credit, or reduction, to the 5
PCA. 6
Q. How would the transfer of excess financial credits 7
be administered? 8
A. Idaho Power proposes that the transfer of excess 9
financial credits be administered similar to its current NEM 10
service offering for customers transferring kWh credits. 11
Customers would submit requests to transfer financial 12
credits by January 31. After reviewing the eligibility of each 13
request, Idaho Power would execute approved transfers no later 14
than March 31. Between the time forms are submitted by the 15
January deadline and the transfers are executed in March, energy 16
generation and consumption will continue to occur, impacting the 17
available balance of financial credits. Therefore, customers 18
would be asked to specify a percent of financial credits to 19
transfer rather than an actual dollar amount. Transfers would be 20
limited to other accounts in the customer’s name and customers 21
would be asked to attest that the account they are transferring 22
credits to is for their own usage. Like the current NEM 23
offering, there would be a $10 charge per meter receiving the 24
credit. 25

ANDERSON, DI 20
Idaho Power Company
Q. Did the Company identify any potential concerns 1
with the proposed transfer of financial credits? 2
A. Yes. The Company does not have the ability to 3
validate that the account where credits would be transferred is 4
for the customer’s own usage, and therefore proposes to rely on 5
an attestation from the customer. The potential for gaming 6
exists if a customer were to put accounts in their name where 7
the usage was not for their own use. The same risk factor exists 8
under the Commission-approved rules for legacy transfer of kWh 9
credits and the Company believes this risk is in part mitigated 10
by the adoption of a project eligibility cap based on the demand 11
at the service point. 12
Q. Is the Company proposing to change the 13
transferability of kWh credits for legacy customers? 14
A. No. In Order No. 32925, the Commission granted 15
limited transferability of kWh credits. In part, the Commission 16
found that: 17
As discussed in prior comments and testimony, 18
even with one delivery point, net metering 19
customers may not pay their full fixed costs 20
given the current rate structure. We find that 21
allowing customers to apply credits to offset 22
usage on continuous meters that are served by 23
the same primary feeder is a reasonable means 24
by which to limit the potential under-recovery 25
of fixed costs. 26
To the extent a legacy on-site generation customer wishes 27
to transfer financial credits to service points not eligible 28
under the rules applicable to legacy systems, that customer can 29

ANDERSON, DI 21
Idaho Power Company
elect to forfeit legacy status. The Customer will take service 1
under the modified on-site generation offering, which will 2
include the flexibility to transfer credits more broadly than 3
what was allowed under NEM. 4
Accumulated kWh Credit Conversion – Non-Legacy Customers 5
Q. How does the Company propose to treat kWh credits 6
that were accumulated prior to the proposed January 1, 2024, 7
effective date? 8
A. The Company proposes that accumulated kWh credits 9
held at service points with non-legacy systems be converted to 10
financial credits one year after the effective date of a 11
Commission-authorized change in compensation structure. 12
Q. Please describe the Company’s recommendation 13
related to the conversion of accumulated kWh credits for 14
customers with non-legacy systems. 15
A. Customers with non-legacy systems would have had 16
the opportunity to accumulate kWh credits from the time they 17
interconnected their system. If the Company’s proposal is 18
approved, these customers would begin receiving financial 19
credits that could be monetized when they have billable amounts 20
to offset. 21
The Company proposes that these customers have one year 22
after moving to the net billing compensation structure to use 23

ANDERSON, DI 22
Idaho Power Company
their pre-existing kWh credit balance from NEM.11 Any remaining 1
kWh credits that have not been used by the customer would be 2
converted to a financial credit on their January 2025 billing 3
cycle. 4
Q. How does the Company propose for kWh credits to 5
convert to a financial credit balance? 6
A. The Company proposes monetization into a financial 7
credit balance at the blended average retail energy rate as of 8
December 31, 2023, for the respective customer class under which 9
they take retail service from Idaho Power. These credits were 10
generated under the NEM compensation structure and to avoid 11
retroactive ratemaking, Idaho Power believes it is reasonable to 12
assume they would have monetized the credits at the applicable 13
blended average energy retail rate in effect while NEM was in 14
place. The final kWh credits will be applied prior to the 15
customer’s January billing cycle. 16
Q. Did the Company consider allowing accumulated kWh 17
credits to continue to be used to offset energy usage beyond one 18
year after implementation of a change in the compensation 19
structure? 20
A. Yes. However, to facilitate the transition from NEM 21
with a one-for-one kWh credit to a net billing financial credit 22

11 Pursuant to the existing Conditions of Purchase and Sale in Schedule 6, 8,
and 84, the Company will process Excess Net Energy (kWh) credit transfer
requests from non-legacy customer-generators in January 2024 and requests to
transfer financial credits will occur December 2024 - January 2025.

ANDERSON, DI 23
Idaho Power Company
approach, the Company suggests converting the kWh credits to 1
financial credits one year after the effective date of net 2
billing to reduce administrative burden and possible customer 3
confusion associated with carrying two separate credit balances. 4
The Company also believes one year post-implementation of a 5
change in the compensation structure gives customers time to use 6
remaining kWh credit balances. 7
Q. How does the Company propose the cost of these 8
financial credits be recovered? 9
A. Under the existing NEM policy, if the accumulated 10
kWh credits were used to offset usage, the cost to R&SGS 11
customers would primarily be recovered from R&SGS customers 12
through the Fixed Cost Adjustment (“FCA”) mechanism. To maintain 13
consistency with the current recovery method, the Company 14
believes it is reasonable to recover the transition cost of 15
converting the accumulated kWh credits to financial credits from 16
R&SGS customers through a one-time adjustment to the FCA balance 17
as of December 31, 2024, which would then be collected in FCA 18
rates from June 1, 2025, through May 31, 2026. 19
In the event there are any remaining accumulated kWh 20
credits for CI&I customers as of December 31, 2024, the Company 21
believes it is reasonable to recover the transition cost of 22
converting those accumulated kWh credits to financial credits 23
through the PCA. 24

ANDERSON, DI 24
Idaho Power Company
For context, as of December 31, 2022, there were 1
approximately 4.7 million non-legacy accumulated kWh credits - 2
the vast majority being residential - which, valued at the then-3
current blended average energy rate was approximately $496,000. 4
Customer Outreach and Education 5
Q. Please explain how the Company will notify 6
customers about its proposal in this docket. 7
A. Coincident with filing this docket, Idaho Power 8
will issue a news release to notify the public of its 9
Application. Additionally, Idaho Power will directly notify its 10
customers of the Application with a bill insert included with 11
their monthly bill. The bill insert will inform all customers 12
that Idaho Power has filed a case requesting changes to the 13
structure and design of its on-site generation offering with a 14
requested effective date of January 1, 2024. A copy of the press 15
release and customer bill insert is included as Attachment 4 to 16
the Application. 17
Q. How will the Company notify existing and pending 18
on-site generation customers of the filing? 19
A. In addition to providing a bill insert to all 20
customers under the major customer classes, the Company will 21
send direct-mail letters to all existing and pending on-site 22
generation customers notifying them that the Company has filed 23
its proposal for changes informed by the Commission-acknowledged 24
VODER Study. The letters that customers with legacy systems 25

ANDERSON, DI 25
Idaho Power Company
receive will also remind them of their legacy status, the 1
criteria for legacy systems, and the reasons legacy status may 2
be forfeited. The letter that customers with non-legacy systems 3
receive will advise them on how they may be impacted by the 4
outcome of the case. All existing and pending on-site generation 5
customers, irrespective of the legacy status of their system, 6
will receive information on how they can participate in the 7
proceeding. A copy of the draft customer letters is included as 8
Attachment 5 to the Application. 9
In addition, the Company will have information available 10
on its website, and customers may contact the Customer Service 11
Center with questions about the filing. 12
Q. Has the Company considered how it would educate 13
existing non-legacy customers about the new compensation 14
structure once it is changed? 15
A. Yes. The Company has considered modifications to 16
customer bill presentment for printed and online bills, as well 17
as modifications to usage and billing information presented 18
through the Company’s MyAccount online and mobile app. 19
Implementing bill and usage presentation changes will provide 20
pertinent details to existing customers to help them better 21
understand how they are billed under real-time net billing. 22
Q. What information will Idaho Power make available to 23
prospective on-site generation customers who seek information 24
about how an installation may impact their Idaho Power bill? 25

ANDERSON, DI 26
Idaho Power Company
A. Customers can access their historical hourly grid 1
consumption data through an online portal or by calling the 2
Customer Service Center. Additionally, generation system hourly 3
production estimates are publicly available from sources such as 4
the National Renewable Energy Laboratory’s PV Watts® Calculator 5
or the customer’s installer. Customers can pair their grid 6
consumption data from Idaho Power with the generation system 7
production data to evaluate the potential economics of 8
installing on-site generation. 9
Idaho Power also understands that its customers are 10
considering considerable investments and strives to provide 11
tools to them where possible. For residential and small general 12
service customers, Idaho Power plans to provide its customers 13
access to a third-party calculator tool on Idaho Power’s 14
website. The calculator will provide the option to use uploaded 15
hourly consumption data in calculations, or a customer can use 16
an estimate of their monthly electric costs if they don’t have 17
twelve months of billing history, or an average electric bill if 18
they have no billing history. For CI&I customers, Idaho Power’s 19
Energy Advisors, and Agriculture Representatives will continue 20
to make additional information available to its customers. 21
Q. In your opinion, does the Company’s plan for 22
customer communication and outreach position it to successfully 23
implement a net billing compensation structure? 24

ANDERSON, DI 27
Idaho Power Company
A. Yes. Idaho Power’s customer relations teams have 1
been thorough and diligent in developing communication 2
strategies and evaluating the option to make a calculator tool 3
available to its customers. Customers can understand real-time 4
net billing, and it is the most accurate and fair measurement of 5
energy flows to and from the customer. 6
The Company endeavors to properly notify all current and 7
prospective on-site generation customers of its proposed changes 8
by sending direct-mail letters and bill inserts. Post-9
implementation, it is also critical to the long-term success of 10
the on-site generation service offering that Idaho Power provide 11
consumption and export information that allows existing 12
customers to understand the bi-directional relationship and 13
impacts on billing. Additionally, prospective on-site generation 14
customers need access to the necessary data and tools to make 15
the most informed and decision based on accurate information – 16
while understanding that the Company’s tariff is subject to 17
change. Idaho Power’s plans for customer communication, billing 18
presentment, and a calculator tool will facilitate a successful 19
shift towards an improved and modernized compensation structure 20
for on-site customer generation. 21
IV. PROPOSED TARIFF REVISIONS 22
Q. What tariff revisions are necessary to implement 23
the Company’s proposal? 24

ANDERSON, DI 28
Idaho Power Company
A. Revisions to Schedules 6, 8, 68, and 84 are 1
necessary to implement the proposed changes in this docket. The 2
Company has included its proposed tariff revisions in Attachment 3
2 to the Application in this docket. 4
Q. Please explain what tariff revisions the Company 5
has proposed for Schedules 6 and 8. 6
A. The Company has included tariff revisions to 7
reflect the change in compensation structure for non-legacy 8
systems from NEM to real-time net billing. The tariff revisions 9
lay out the compensation structure that would be separately 10
applicable to customers with legacy and non-legacy systems. The 11
“conditions to purchase and sale” have been separated into three 12
sections. The first are those provisions that only apply to 13
legacy systems under the NEM compensation structure and the 14
second are those provisions that only apply to non-legacy 15
systems under the proposed net billing compensation structure. 16
The third section includes provisions that broadly apply to all 17
customers taking service under Schedule 6 and 8. The revised 18
tariff also includes line items for the ECR applicable to non-19
legacy systems, and specifies the proposed change in the 20
administration of energy storage devices towards the 25 kW cap. 21
Finally, the Company has proposed a few minor operational 22
administrative items. 23
Q. Please summarize the revisions the Company has 24
proposed for Schedule 84. 25

ANDERSON, DI 29
Idaho Power Company
A. The proposed revisions to Schedule 84, similar to 1
those for Schedules 6 and 8, account for a modification to the 2
service offering from NEM to real-time net billing for customers 3
with non-legacy systems and the administration of energy storage 4
devices. In addition, the revisions to Schedule 84 define the 5
modification to the project eligibility cap for non-legacy 6
systems. 7
Q. What revisions has the Company proposed for 8
Schedule 68? 9
A. As more fully explained in Mr. Ellsworth’s 10
testimony, the Company has included modifications to update the 11
interconnection requirements for Schedule 84 customers that 12
install systems larger than 100 kW. Schedule 68 also reflects 13
minor administrative updates for the interconnection process. 14
V. PROPOSED SCHEDULE FOR ECR UPDATES 15
Q. Mr. Ellsworth’s testimony describes the Company’s 16
proposed methodology for establishing an ECR and methods the 17
Company is proposing for valuing each of the components of the 18
ECR. What is the Company’s proposed timing and frequency for 19
updating the ECR? 20
A. The Company recommends an annual ECR update filed 21
in April, where Commission-approved updates would take effect 22
June 1 each year, concurrent with other spring filing and 23
seasonal rate changes. The primary driver for the proposed 24
update schedule is to ensure that Energy Imbalance Market Load 25

ANDERSON, DI 30
Idaho Power Company
Aggregation Point (“ELAP”) hourly prices have been disputed and 1
reconciled. The Company also believes it is important from a 2
timing perspective to have the effective ECR changes occur in 3
June in advance of the summer season. 4
Q. Please describe the Company’s proposed update cycle 5
for each of the respective methods and components of the ECR. 6
A. The Company has identified updates for the proposed 7
methods as fitting into two general categories: (1) annual 8
updates, and (2) routine updates less frequent than annual. The 9
routine updates that are less frequent than annual are informed 10
by other filings or studies, such as Idaho Power’s Integrated 11
Resource Plan (“IRP”). Table 1 provides a summary of each of the 12
inputs to the ECR and the proposed update cadence. Annual 13
updates will rely on data from the most recent twelve months 14
ending December 31 and routine updates will rely on the most 15
recently available information at the time of its annual filing 16
to update the ECR. 17
// 18
19
20
21
22
23
24
25

ANDERSON, DI 31
Idaho Power Company
Table 1 1
ECR Proposed Update Schedule by Input 2
3
Q. How does the Company propose to update the avoided 4
energy component of the ECR? 5
A. The avoided energy value would be updated annually 6
using the most recent 12 months, ending December 31, for both 7
customer-generator exports and ELAP prices. ELAP hourly settled 8
price corrections are typically available within approximately 9
60 days – this timing, in part, drives the Company’s proposed 10
update schedule to file in April of each year. 11
Q. How does the Company propose to update the avoided 12
generation capacity component of the ECR? 13
A. The avoided generation capacity calculation would 14
be updated annually to reflect real-time customer exports and 15
Input ECR Component Type of Update
Real-Time Exports
12 months ending Dec 31
Avoided Energy;
Avoided Generation Capacity
Annual
ELAP Hourly Market Prices
12 months ending Dec 31
Avoided Energy Annual
Contribution Capacity - ELCC
3-year rolling average
Avoided Generation Capacity Annual
Peak Annual Exports
Total MW
Avoided Generation Capacity Annual
Levelized Cost of Avoided Resource
Cost per kW-year
Avoided Generation Capacity Routine - Most recently
filed IRP
Hours of Capacity Need
On-Peak Hours
Avoided Energy;
Avoided Generation Capacity
Routine - Most recently
filed IRP
Transmission & Distribution Deferral
Annual Deferral Value
Avoided Transmission &
Distribution Capacity
Routine - Most recently
filed IRP
Line Loss Study
Loss Coefficients
Avoided Line Losses Routine - Updated with
periodic line loss study
Variable Energy Resource Integration
Study
Integration Costs Routine - Updated with
periodic VER Study

ANDERSON, DI 32
Idaho Power Company
peak annual export for the most recent calendar year. As 1
described by Mr. Ellsworth, the ECR would utilize a three-year 2
rolling average ELCC calculation to mitigate year-to-year 3
volatility. The annual update would rely on the most-recently 4
filed IRP for defining the on-peak hours and the value of the 5
levelized cost of the avoided resource. 6
Q. Please describe how the Company plans to update the 7
T&D capacity value. 8
A. The annual update for the T&D capacity value 9
component of the ECR will reference the most recently filed IRP. 10
The calculation of the T&D capacity value relies on the same 20 11
years of project data that are used to determine IRP energy 12
efficiency values. This data includes 15 years of historical 13
data and 5 years of projected data. 14
Q. How does the Company propose to update the avoided 15
line loss value to inform the proposed annual ECR updates? 16
A. The annual update for the ECR will rely on the most 17
recently completed line loss study. Line loss studies are 18
comprised of extensive analyses and are not performed on a 19
frequent basis; however, line losses are expressed as 20
percentages, which do not significantly vary over time. 21
Therefore, the periodic update of the input is reasonable and 22
will not negatively impact customer-generators or non-23
participants. 24

ANDERSON, DI 33
Idaho Power Company
Q. How does the Company propose to update the 1
integration costs in the ECR annual update? 2
A. The annual ECR update will rely on the most 3
recently completed VER Integration Study. As explained in Mr. 4
Ellsworth’s testimony, integration studies are completed 5
periodically, based on current and expected variable non-6
dispatchable resources on the Company’s system. The annual 7
update would incorporate updated integration costs into the ECR 8
in the annual update subsequent to completion of the next VER 9
Integration Study. 10
VI. CONCLUSION 11
Q. Does the Company’s proposal to modify the Schedule 12
84 project eligibility cap, other implementation considerations, 13
and the proposed schedule for ECR updates meet the Company’s 14
primary objectives in this case? 15
A. Yes. The Company’s objectives provide the 16
foundation for proposing changes to the project eligibility cap 17
and excess energy transfer process that will provide additional 18
flexibility and opportunities for customers to install on-site 19
generation. The proposed schedule for ECR updates is repeatable 20
and will ensure timely recognition of changing conditions on 21
Idaho Power’s system and the broader power markets. Last, the 22
proposed tariff revisions and planned customer education and 23
outreach regarding a change to a net billing compensation 24
structure provide for enhanced customer understandability. 25

ANDERSON, DI 34
Idaho Power Company
Q. Does this conclude your testimony? 1
A. Yes. 2
// 3

ANDERSON, DI 35
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 in this matter. 8
3. To the best of my knowledge, my pre-filed direct 9
testimony and exhibits are true and accurate. 10
I hereby declare that the above statement is true to the 11
best of my knowledge and belief, and that I understand it is 12
made for use as evidence before the Idaho Public Utilities 13
Commission and is subject to penalty for perjury. 14
SIGNED this 1st day of May 2023, at Boise, Idaho. 15
16
17
Signed: _______________________ 18

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-23-14

IDAHO POWER COMPANY

ANDERSON, DI
TESTIMONY

EXHIBIT NO. 6

Schedule 6 - Residential On-Site Generation Non-Le ac Bill Impact
Average Energy Delivered/Imported Average Energy Received/Exported Average Bill Impact
Energy Delivered Energy Exported Avg. Monthly Bill
Category Count NEM Net Billing Category Count NEM Net Billing Category Count NEM Net Billing
0 kWh 642 0 524 0 kWh 642 289 672 0 kWh 642 5.00$ 11.56$
1 ≤ 500 kWh 2,123 211 686 1 ≤ 500 kWh 2,123 103 475 1 ≤ 500 kWh 2,123 22.50$ 34.88$
500 ≤ 900 kWh 563 672 1,163 500 ≤ 900 kWh 563 64 491 500 ≤ 900 kWh 563 62.38$ 76.23$
900 ≤ 1,300 kWh 197 1,078 1,623 900 ≤ 1,300 kWh 197 63 545 900 ≤ 1,300 kWh 197 99.31$ 115.60$
1,300 ≤ 1,700 kWh 110 1,486 2,060 1,300 ≤ 1,700 kWh 110 57 574 1,300 ≤ 1,700 kWh 110 137.46$ 155.75$
1,700 kWh+119 2,491 2,964 1,700 kWh+119 20 473 1,700 kWh+119 235.01$ 251.90$
All Customers 3,754 399 891 All Customers 3,754 123 517 All Customers 3,754 39.63$ 51.75$
399
891
NEM Net Billing
Average Energy Delivered/Imported
0 211
672 1,078 1,486
2,491
524 686
1,163
1,623 2,060
2,964
0 kWh(642 customers)1 ≤ 500 kWh (2,123 customers)500 ≤ 900 kWh (563 customers)900 ≤ 1,300 kWh (197 customers)1,300 ≤ 1,700 kWh (110 customers)1,700 kWh+(119 customers)
Average Net Monthly kWh Delivered
Average Energy Delivered
NEM Net Billing
123
517
NEM Net Billing
Average Energy Received/Exported
$39.63
$51.75
NEM Net Billing
Average Bill Impact
289
103 64 63 57 20
672
475 491 545 574
473
0 kWh(642 customers)1 ≤ 500 kWh (2,123 customers)500 ≤ 900 kWh (563 customers)900 ≤ 1,300 kWh (197 customers)1,300 ≤ 1,700 kWh (110 customers)1,700 kWh+(119 customers)
Average Net Monthly kWh Delivered
Average Energy Received/Exported
NEM Net Billing
$5 $23
$62
$99
$137
$235
$12 $35
$76
$116
$156
$252
0 kWh(642 customers)1 ≤ 500 kWh (2,123 customers)500 ≤ 900 kWh (563 customers)900 ≤ 1,300 kWh (197 customers)1,300 ≤ 1,700 kWh (110 customers)1,700 kWh+(119 customers)
Average Net Monthly kWh Delivered
Average Monthly Bill Impact
NEM Net Billing
Exhibit No. 6 Case No. IPC-E-23-14 G. Anderson, IPC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-23-14
IDAHO POWER COMPANY
ANDERSON, DI
TESTIMONY
EXHIBIT NO. 7
Schedule 8 - Small General Service On-Site Generation Non-Le ac Bill Impact
Average Energy Delivered/Imported Average Energy Received/Exported Average Bill Impact
Energy Delivered Energy Exported Avg. Monthly Bill
Category Count NEM Net Billing Category Count NEM Net Billing Category Count NEM Net Billing
0 kWh 6 - 439 0 kWh 6 652 943 0 kWh 6 5.00$ 10.09$
1 ≤ 200 kWh 4 100 631 1 ≤ 200 kWh 4 191 532 1 ≤ 200 kWh 4 15.02$ 38.36$
200 ≤ 400 kWh 1 248 1,248 200 ≤ 400 kWh 1 517 1,000 200 ≤ 400 kWh 1 30.32$ 61.25$
400 ≤ 600 kWh - - - 400 ≤ 600 kWh - - - 400 ≤ 600 kWh - -$ -$
600 ≤ 800 kWh - - - 600 ≤ 800 kWh - - - 600 ≤ 800 kWh - -$ -$
800 kWh+2 989 1,357 800 kWh+2 11 368 800 kWh+2 108.75$ 126.72$
All Customers 13 202 702 All Customers 13 401 732 All Customers 13 25.99$ 40.67$
202
702
NEM Net Billing
Average Energy Delivered/Imported
-100 248
- -
989
439
631
1,248
- -
1,357
0 kWh(6 customers)1 ≤ 200 kWh (4 customers)200 ≤ 400 kWh (1 customers)400 ≤ 600 kWh (0 customers)600 ≤ 800 kWh (0 customers)800 kWh+(2 customers)
Average Net Monthly kWh Delivered
Average Energy Delivered
NEM Net Billing
401
732
NEM Net Billing
Average Energy Received/Exported
$25.99
$40.67
NEM Net Billing
Average Bill Impact
652
191
517
- -11
943
532
1,000
- -
368
0 kWh(6 customers)1 ≤ 200 kWh (4 customers)200 ≤ 400 kWh (1 customers)400 ≤ 600 kWh (0 customers)600 ≤ 800 kWh (0 customers)800 kWh+(2 customers)
Average Net Monthly kWh Delivered
Average Energy Received/Exported
NEM Net Billing
$5 $15 $30
$- $-
$109
$10
$38
$61
$- $-
$127
0 kWh(6 customers)1 ≤ 200 kWh (4 customers)200 ≤ 400 kWh (1 customers)400 ≤ 600 kWh (0 customers)600 ≤ 800 kWh (0 customers)800 kWh+(2 customers)
Average Net Monthly kWh Delivered
Average Bill Impact
NEM Net Billing
Exhibit No. 7 Case No. IPC-E-23-14 G. Anderson, IPC
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-23-14
IDAHO POWER COMPANY
ANDERSON, DI
TESTIMONY
EXHIBIT NO. 8
Schedule 9/84 - Large General Service On-Site Generation Non-Legacy Bill Impact
Average Energy Delivered Average Energy Received/Exported Average Bill Impact
Energy Delivered Energy Exported Avg. Monthly Bill
Category Count NEM Net Billing Category Count NEM Net Billing Category Count NEM Net Billing
0 kWh 2 - 556 0 kWh 2 2,990 3,505 0 kWh 2 16.00$ 16.00$
1 ≤ 500 kWh 2 299 841 1 ≤ 500 kWh 2 152 542 1 ≤ 500 kWh 2 43.86$ 61.29$
500 ≤ 900 kWh 2 648 2,349 500 ≤ 900 kWh 2 752 1,701 500 ≤ 900 kWh 2 60.03$ 76.52$
900 ≤ 1,300 kWh 1 1,209 1,638 900 ≤ 1,300 kWh 1 73 429 900 ≤ 1,300 kWh 1 117.57$ 131.40$
1,300 ≤ 1,700 kWh 1 1,615 2,684 1,300 ≤ 1,700 kWh 1 231 1,069 1,300 ≤ 1,700 kWh 1 135.77$ 152.49$
1,700 kWh+- - - 1,700 kWh+- - - 1,700 kWh+- -$ -$
All Customers 8 590 1,477 All Customers 8 1,011 1,624 All Customers 8 61.64$ 73.94$
590
1,477
NEM Net Billing
Average Energy Delivered
-299 648
1,209 1,615
-
556 841
2,349
1,638
2,684
-
0 kWh
(2 customers)1 ≤ 500 kWh (2 customers)500 ≤ 900 kWh (2 customers)900 ≤ 1,300 kWh (1 customers)1,300 ≤ 1,700 kWh (1 customers)
1,700 kWh+
(0 customers)
Average Net Monthly kWh Delivered
Average Energy Delivered
NEM Net Billing
1,011
1,624
NEM Net Billing
Average Energy Received/Exported
$61.64
$73.94
NEM Net Billing
Average Bill Impact
2,990
152
752
73 231 -
3,505
542
1,701
429
1,069
-
0 kWh(2 customers)1 ≤ 500 kWh (2 customers)500 ≤ 900 kWh (2 customers)900 ≤ 1,300 kWh (1 customers)1,300 ≤ 1,700 kWh (1 customers)1,700 kWh+(0 customers)
Average Net Monthly kWh Delivered
Average Energy Received/Exported
NEM Net Billing
$16
$44 $60
$118 $136
$-$16
$61 $77
$131 $152
$-
0 kWh(2 customers)1 ≤ 500 kWh (2 customers)500 ≤ 900 kWh (2 customers)900 ≤ 1,300 kWh (1 customers)1,300 ≤ 1,700 kWh (1 customers)1,700 kWh+(0 customers)
Average Net Monthly kWh Delivered
Average Bill Impact
NEM Net Billing
Exhibit No. 8 Case No. IPC-E-23-14 G. Anderson, IPC
Page 1 of 1