20240208Study Supplement.pdf

1407 W. North Temple, Suite 330 Salt Lake City, UT 84116
February 8, 2024

VIA ELECTRONIC DELIVERY Commission Secretary Idaho Public Utilities Commission
11331 W. Chinden Blvd
Building 8 Suite 201A Boise, ID 83714 RE: CASE NO. PAC-E-23-17
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER TO COMPLETE THE STUDY REVIEW PHASE OF THE STUDY OF THE COSTS AND BENEFITS OF ON-SITE CUSTOMER GENERATION Attention: Commission Secretary

Please find attached Rocky Mountain Power’s electronic filing of its on-site generation study supplement (Study Supplement) to its on-site generation study which was filed on June 29th, 2023. The Study Supplement is intended to replace the previously submitted study in its entirety. The
company is submitting the Study Supplement in response to a request from commission staff. The
supplement includes revisions and additions that were made in collaboration with commission staff. Informal inquiries may be directed to Mark Alder, Idaho Regulatory Manager at [phone].

Very truly yours,
Joelle Steward
Senior Vice President, Regulation and Customer & Community Solutions Enclosures CC: Service List – Case No. PAC-E-23-17

RECEIVED
2023 February 8, 2023 3:35PM
IDAHO PUBLIC
UTILITIES COMMISSION

SUPPLEMENT TO ROCKY
MOUNTAIN POWER’S ON-SITE
GENERATION STUDY
PAC-E-19-08 Net Metering IPUC Order No. 34753
February 2024

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Table of Contents
Table of Contents ............................................................................................................................. i
List of Tables ................................................................................................................................... iii
List of Figures .................................................................................................................................. iv
List of Appendices ............................................................................................................................ v
Study Scope ..................................................................................................................................... vi
Glossary ........................................................................................................................................... xi
1.0 Executive Summary ................................................................................................................... 1
2.0 Introduction .............................................................................................................................. 1
2.1 Current Net Metering Summary ........................................................................................... 1
2.2 Regulatory History ................................................................................................................ 3
3.0 Netting Period ........................................................................................................................... 4
3.1 Summary of Instantaneous, Monthly, and Hourly Billing ..................................................... 4
3.2 Class Revenue Requirement ................................................................................................. 4
3.3 Class Export Payment ............................................................................................................ 7
3.4 Bill Impacts ............................................................................................................................ 8
3. 5 Administrative Costs ............................................................................................................ 9
4.0 Export Credit Rate ................................................................................................................... 10
4.1 Modeled Data as an Estimate for Actual Customer Export Data ....................................... 11
4.2 Model Validation Method ................................................................................................... 12
4.3 Avoided Energy Value ......................................................................................................... 16
4.3.1 Supporting Documentation for Avoided Energy Value ................................................... 17
4.3.2 Supporting Documentation for Non-Firm Energy ........................................................... 18
4.4 Avoided Capacity Value ...................................................................................................... 20
4.4.1 Loss of Load Probability Study ..................................................................................... 21
4.4.2 Historical Peak Conditions ........................................................................................... 22
4.4.3 Time-Differentiated Capacity Values ........................................................................... 23
4.5 Avoided Risk ........................................................................................................................ 24
5.0 Project Eligibility Cap .............................................................................................................. 25
6.0 Avoided Transmission and Distribution Costs ........................................................................ 26
7.0 Avoided Line Losses ................................................................................................................ 27

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8.0 Integration Costs ..................................................................................................................... 29
9.0 Avoided Environmental Costs and Other Benefits ................................................................. 30
9.1 Grid Stability, Resiliency, and Cybersecurity ...................................................................... 30
9.1.1 Grid Benefits of On-Site Generation with Storage ...................................................... 30
9.1.2 Community Resiliency Benefits of Customer Generation with Storage ...................... 31
9.1.3 Customer Generation and Cybersecurity Protection .................................................. 31
9.2 Public Health and Safety ..................................................................................................... 32
9.3 Economic Benefits ............................................................................................................... 32
9.4 Possible Net Value of Renewable Energy Credits ............................................................... 33
9.5 Reduced Risk from End-of-Life Disposal ............................................................................. 33
10.0 Recovering Export Credit Rates in the ECAM ....................................................................... 34
10.1 Current Export Credit Recovery ........................................................................................ 34
10.2 Recovery Allocation .......................................................................................................... 34
10.3 Export Credit Price Scenarios ............................................................................................ 35
11.0 Schedule 136 Implementation Issues ................................................................................... 36
11.1 Billing Structure ................................................................................................................. 36
11.1.1 Time-of Delivery Pricing ............................................................................................. 36
11.1.2 Economic Evaluation for Customer-Generators and On-Site Generation System
Installers ................................................................................................................................ 38
11.1.3 Residential Solar Energy Disclosure Act ..................................................................... 39
11.2 Export Credit Expiration .................................................................................................... 39
11.2.1 Accumulated Export Credits ...................................................................................... 39
11.2.2 Impact to Customers over Various Expiration Periods .............................................. 40
11.2.3 Export Credit Expiration Policy .................................................................................. 43
11.2.4 Treatment of Financial Credits .................................................................................. 43
11.2.5 Treatment of Existing Credits for Non-Legacy Customer Generators ....................... 44
11.3 Export Credit Updates ....................................................................................................... 45
11.3.1 SAR Energy Rates Updates and IRP Cycle Impact to Export Credit Updates ............. 45
12.0 Smart Inverter Study ............................................................................................................. 46

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List of Tables
Name Location
Table 2.1: Idaho On-site Generation Customer Count as of 12/31/2022 2.1
Table 2.2: Average Size of On-Site Generation Customer’s System 2.1
Table 3.1: Comparison of Generation to Exports under Different Netting Scenarios 3.2
Table 3.2: Revenue Requirement Changes from Traditional Net Metering 3.2
Table 3.3: Export Payments by Class 3.3
Table 3.4: Bill Impacts by Class 3.4
Table 4.1: Summary of Export Credit Costs 4.0
Table 4.2: Northern Utah Customers and Idaho System Size (Installed Capacity) 4.2
Table 4.3: Northern Utah Customers and Idaho Average 2022 Monthly Exports 4.2
Table 4.4: Solar Production Difference - Weighted Mean Absolute Percentage Errors 4.2
Table 4.5: Customer Generation Exports During Peak Loads 4.4
Table 4.6: Capacity Value by Time of Use Period 4.4
Table 5.1: Pros and Cons of a Generic Cap (25 kW for Residential and 100 kW for Non-
Residential) 5.0
Table 7.1: Idaho 2018 Demand and Energy Loss Summary 7.0
Table 10.1: Net Metering Reduction in Revenue by Class 10.2
Table 10.2: Annual Export Costs by Rate 10.3
Table 11.1: Pros and Cons of Seasonal and Time of Use Export Credit Pricing 11.1
Table 11.2: Illustrative Export Credit Prices Under Different Modes of Time Granularity 11.1
Table 11.3: Excess kWh Total as of 8/1/2020 11.2
Table 11.4: Percentage of Customers Overproducing Annually 11.2
Table 11.5: Weighted Average of Customer Overproduction 11.2
Table 11.6: Pros and Cons of Different Treatments for Financial Credits from Excess
Exported Energy 11.2
Table 11.7: Impact of Different Update Cycles 11.3

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List of Figures
Name Location
Figure 2.1: On-site Generation Customer Adoption 2.1
Figure 4.1: Northern Utah Customers and Idaho Monthly Exports Comparison 4.2
Figure 4.2: Weighted LOLP Distribution 4.4
Figure 7.1: Transmission, Primary, and Secondary Components of an Electrical System 7.0
Figure 11.1: Frequency of Export Credit Updates 11.3

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List of Appendices
Name
Relevant Study
Location
Appendix 3.1: Customer Generator Export and Generation Information 3.0
Appendix 4.1: Export Profile Jan21-Dec22 4.0
Appendix 4.2: Export Credit Calculation 4.0
Appendix 4.3: Customer Generation Exports During Peak Loads 4.0
Appendix 4.4: Idaho Export Profile Validation Avg Capacity 4.2
Appendix 4.5: ID Export Profile Validation Monthly Exports 4.2
Appendix 4.6: ID Export Profile Validation PV Watts Production 4.2
Appendix 4.7: Appendix K - Capacity Contribution - 2021 IRP 4.4
Appendix 7.1: PacifiCorp-Idaho 2018 Electric System Loss Study 7.0
Appendix 8.1: Appendix F - Flexible Reserve Study- 2021 IRP 8.0
Appendix 8.2: Wind and Solar Integration Charges Approved in Order No. 34966 8.0
Appendix 11.1: Weighted Average Overproduction 11.2
Appendix 11.2: Idaho Expired Credit Analysis 2012-2022 11.2
Appendix 11.3: Customer Impact at 2-, 5-, and 10-Year Expiration 11.2
Appendix 11.4: SAR Export Credit Analysis 11.3
Appendix 12.0: Utah STEP - Smart Inverter Study 12.0

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Study Scope
Item
Number Subject Order No. 34753 – Attachment A: Scope of Rocky Mountain Power’s On-Site Generation Study
1 Netting Period
existing customer-generators netted their energy
exports: a. Monthly
b. Hourly
each of the existing customer-generators net their
energy exports: a. Monthly
b. Hourly
stratified by usage, if energy exports are netted: a.
Monthly
b. Hourly
c. Instantaneously
(Modeled Data as
a Proxy for Actual
Customer Export
Data)
will be available for customer-generators.

(Modeled Data as
a Proxy for Actual
Customer Export
Data)
validating the accuracy of its model and modeled
customer export data.
(Avoided Energy
Value)
the energy price assumptions in the Company’s most
recently acknowledged Integrated Resource Plan
(Avoided Energy
Value)
why the avoided cost of exported energy produced by
customer-generators should only be valued at 85% of

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Item
Number Subject Order No. 34753 – Attachment A: Scope of Rocky Mountain Power’s On-Site Generation Study
8 Export Credit Rate
(Avoided Capacity
Value)
provided by customer-generators on a class basis
using one of two methods:
a. a Loss of Load Probability Study, or
b. Determine the power that is reliably exported to
the grid by net metering during peaking events. Use
the top 100 peaking events from each of the past 10
years (1,000 peaking events). Use a reliability
threshold of 99.5%. If, for example, the study
determines that customer-generators provide no less
than 1.5 MW of power during 99.5% of the peaking
events, then use 1.5 MW as the basis for determining
the capacity avoided by the customer-generator class.
(Avoided Capacity
Cap

project eligibility cap according to a customer’s
demand as opposed to predetermined caps of 25 kW
and 100 kW. a. Analyze at 100% of demand.
Transmission and
Distribution Costs

costs that could be avoided by energy exported to the
grid by net metering customers using the
methodology for calculating the avoided transmission
and distribution costs provided by energy efficiency
Losses that an average customer can understand.
costs of net metering customers as a class. Calculate
the dollar impact of deferring a study of the
integration charges for net metering customers until
AMI data is available, and if different, calculate the
dollar value of using a zero placeholder until AMI data

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Item
Number Subject Order No. 34753 – Attachment A: Scope of Rocky Mountain Power’s On-Site Generation Study
15 Avoided
Environmental
Costs and Other
Benefits
resiliency, and cybersecurity protection provided by
on-site generators as a class and different penetration
levels.
Environmental
Costs and Other
Benefits

from reduced local impacts of global warming such as
reduced extreme temperatures, reduced snowpack
variation, reduced wildfire risk, and other impacts
that can have direct impacts on Rocky Mountain
Environmental
Costs and Other
Benefits
creation and increased economic activity in the
immediate service territory.
Environmental
Costs and Other
Benefits
Credit sales produced by net metering exported
energy.
Environmental
Costs and Other
Benefits
concerns for the Company compared to fossil-fueled
resources.
Credit Rates in the
ECAM
metering bill credit costs.
Credit Rates in the
ECAM
metering costs allocated to each class.
Credit Rates in the
ECAM
allocated and recovered between rate classes for the
past five years.
Credit Rates in the
ECAM
that the Export Credit Rate is the retail rate, 7.4
cents/kWh, 5 cents/kWh, or 2.23 cents/kWh.

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Item
Number Subject Order No. 34753 – Attachment A: Scope of Rocky Mountain Power’s On-Site Generation Study
24 Recovering Export
Credit Rates in the
ECAM
recovered by rate class through the Company’s
proposed ECAM method going forward.
Implementation
Issues (Billing
differences will be used to help align customer
generated exported energy with the Company’s
Implementation
Issues (Billing
for differentiating energy and capacity credits could
be used to more closely align customer-generated
Implementation
Issues (Billing
Structure)
site generation system installers will have accurate
and adequate data and information to make informed
choices about the economics of on-site generation
Implementation
Issues (Billing
Structure)
be able to comply with the Residential Solar Energy
Disclosure Act if hourly or instantaneous netting
and/or granular time-differentiated export rates are
Implementation
Issues (Export
accumulated export credits as of August 1, 2020.
Implementation
Issues (Export
and 10-year expiration periods.
Implementation
Issues (Export
Credit Expiration)
a. Show how the Company does or does not benefit
from the expiration of customer export credits.
b. Show how non net bill customers are harmed or
benefited from the expiration of customers export
Implementation
Issues (Frequency
of Export Credit
Updates)
to annual updates of the Export Credit Rate by
comparing the changes in the SAR energy rate, line
losses, and integration costs using historical data over
one year, one IRP cycle (two years), and two IRP

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Item
Number Subject Order No. 34753 – Attachment A: Scope of Rocky Mountain Power’s On-Site Generation Study
33 Smart Inverter
Study

inverter policy and quantify the benefits of applying
that policy in its Idaho service territory, in particular,

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Glossary
90/110 performance band – A PURPA generator’s energy deliveries plus or minus 10% from its
forecasted performance.
Automated Meter Infrastructure (AMI) – Integrated system of smart meters, communications
networks, and data management systems that enables two-way communication between
utilities and customers.
Distributed Energy Resource (DER) – A small-scale supply or demand resource that is usually
situated near sites of electricity use.
Energy Imbalance Market (“EIM”) – The EIM automatically balances demand every five
minutes with the lowest cost energy available across the participating grids.
Export Credit Rate (ECR) – The total credit to the customer once a customer’s generation is
netted by either real-time billing or interval netting.
Flexible Reserve Study (FRS) – Estimates the regulation reserve required to maintain
PacifiCorp’s system reliability and comply with North American Electric Reliability Corporation
(NERC) reliability standards as well as the incremental cost of this regulation reserve.
Instantaneous Billing – Method of calculating customer-generator billing where the customer’s
financial credit for exports and the customer’s retail charges are calculated separately and the
net result is either charged or credited to the customer.
Integrated Resource Plan (IRP) – The IRP is a comprehensive decision support tool and
roadmap for meeting the company's objective of providing reliable and least-cost electric
service to all our customers. Developed with involvement from state utility commission staff,
state agencies, customer and industry advocacy groups, project developers, and other
stakeholders the IRP focuses on the first 10 years of a 20-year planning period and includes the
preferred portfolio of supply-side and demand-side resources to meet this need. PacifiCorp
prepares its integrated resource plan on a biennial schedule, filing its plan with state utility
commissions during each odd numbered year.
Integration Costs – The additional expense when variable energy resources are added to a
portfolio. Typically includes costs related to the uncertainty and variation in variable energy
resource output from moment to moment. For distributed resources, integration costs could
potentially include equipment and/or operational changes to manage impacts on the
distribution system.
Interval Netting – Method of calculating customer billing where the total electricity consumed
and generated is calculated for a given interval and the output of that calculation is included on
a customer’s bill.
Line Losses – Loss of electricity due to the resistance of the conductor, or line, against the flow
of the current, or electricity.

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Loss of Load Probability (“LOLP”) – Likelihood of a risk of loss of load event where system load
and/or reserve obligations could not be met with available resources.
Net Billing – As defined by Electric Service Schedule 136, charges for all electricity supplied by
the Company and netted by the export credit for the electricity generated by an eligible
customer and fed back to the electric grid over the applicable billing period. Net billing differs
from net metering because net billing customers do not get a credit in kWh but instead all net
energy exports are credited to the customer at the exported customer-generated energy credit
rate.
Net Metering – As defined by Electric Service Schedule 135, the difference between the
electricity supplied by the Company and the electricity generated by an eligible customer and
fed back to the grid over the applicable billing period. Net metering may also refer to on-site
generation or a distributed energy resource in general.
The Public Utility Regulatory Policies Act of 1978 (“PURPA”) – Enacted following the energy
crisis of the 1970s to encourage cogeneration and renewable resources and promote
competition for electric generation.
Qualifying Facility (“QF”) – a generation facility that meets certain ownership, operating, and
other criteria established by the Federal Energy Regulatory Commission (“FERC”) according to
the Public Utility Regulatory Policies Act of 1978 (“PURPA”)
Renewable Energy Certificates (“RECs”) – The property rights to the environmental, social, and
other non-power attributes of renewable electricity generation. RECs are issued when one
megawatt-hour (MWh) of electricity is generated and delivered to the electricity grid from a
renewable energy resource.
Surrogate Avoided Resource ("SAR") Methodology – Method for determining avoided costs for
standard qualifying facility resources up to at least 100 kW in nameplate capacity. Under the
SAR Methodology, avoided energy costs reflect forecast prices for natural gas and the assumed
heat rate of a combined cycle combustion turbine. Monthly weighting factors are used to
differentiate avoided costs by month, and an adjustment of 85 percent is applied to non-firm
resources.

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1.0 Executive Summary
Rocky Mountain Power, a division of PacifiCorp (“PacifiCorp” or the “Company”) presents this
study (“Study”) to evaluate methods, inputs, and assumptions for valuing on-site generation
that is exported to the grid. The Idaho Public Utilities Commission (“Commission”) approved the
scope of this study (“Study Scope") of on-site generation on August 26, 2020.1
The Study provides the Commission and stakeholders with the information needed to consider
changes to the export credit rate (“ECR") for on-site customer generators in the future. The
purpose of this Study is not to propose a specific ECR at this time but to initiate a review and
obtain feedback on potential considerations for valuing an ECR.
The Study gives a snapshot of its current approximately 2,200 on-site customer generation
customers in Idaho. Data for modeling different components of the ECR was based on Utah
customers in the same climate zone as Idaho customers.
The effects of netting imports monthly, hourly, and instantaneously were studied to show the
effects for each scenario. As guided by the Commission’s Study Scope, the avoided cost of
exported energy was calculated using the same price assumptions as the Company’s most
recently acknowledged integrated resource plan (“IRP”) and the capacity value of exported
energy was analyzed using the loss of load probability (“LOLP”) study. The avoided capacity
value of on-site generators was modeled during PacifiCorp’s highest risk-of-loss-of-load-event
hours to evaluate potential contribution of on-site generation during the grid’s most strained
hours. Different export credit scenarios were analyzed to show the annual export costs at
various ECRs. The Study concludes by looking at the different implementation issues for an ECR
including how different customers would be affected by expired credits and the effects of
updating the ECR at different frequencies.
2.0 Introduction
2.1 Current Net Metering Summary
As of December 31, 2022, there are 2,196 on-site generating customers connected to
PacifiCorp’s system in Idaho. The majority of those customers are residential using solar
photovoltaic (“PV”) systems. There are also 61 wind generation customers and five customers
with a mix of electricity sources or with hydro generators.

1 In the Matter of the Application of Rocky Mountain Power to Close the Net Metering Program to New Service &
Implement a Net Billing Program to Compensate Customer-Generators for Exported Generation. Case No. PAC-E-19-08, Order No. 34753.

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Table 2.1: Idaho On-Site Generation Customer Count as of 12/31/2022
Other
2,055 54 5 2,114
63 5 - 68
8 2 - 10
4 - - 4

Net metering customers participate in the Company’s customer generation programs through
Schedules 135 or 136. Residential and general service customers taking service on Schedules 1,
23, 23A, or 36 must not have a generating capacity greater than 25 kilowatts (kV). All other
customers are limited to a generating capacity of 100 kW. Schedule 135 closed to new
applicants as of October 2, 2020. The average size of a residential customer’s solar PV system is
8.1 kW, as of December 31, 2022.2
Table 2.2: Average Size of On-Site Generation Customer’s System
(average) (average) kW (average)
8.1 3.75 12.35
16.95 9.44 -
44.74 2.4 -
21.58 - -

On-site generation customer growth has increased steadily over the last 10 years with an
annual average growth rate of 40%. While customer growth has moderated slightly during the
last 3 years in percentage terms, 2022 saw the most on-site customers connecting to the
system with a total of 500 new customers added.

2 For more detail on the customer size, generation type, and customer system size, see the system size tab of
Appendix 11.2: Idaho Expired Credit Analysis 2012-2022

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Figure 2.1: On-Site Generation Customer Adoption

2.2 Regulatory History
PacifiCorp began offering Electric Service Schedule 135 - Net Metering Service, in 2003, as
approved by Order No. 29260 in Case No. PAC-E-03-4. The case was initiated following a
petition by the NW Energy Coalition which requested a net metering schedule in Idaho
following approval of net metering schedules for Idaho Power Company and Avista. In that
case, PacifiCorp proposed Schedule 135, which was patterned from Idaho Power’s net metering
Schedule 84.
Schedule 135, as approved by Order No. 29260, limited participation on Schedule 135 to no
more than 25 kilowatts for customers taking service on Schedules 1, 36, 23, or 23A and to 100
kilowatts for all other customers. Customers taking service on Schedules 1, 36, 23 or 23A were
to be credited for excess net energy at the customer’s standard service rate and all other
customers would be credited net excess energy at a rate that equals 85 percent of the monthly
weighted average of the daily on-peak and off-peak Dow Jones Mid-Columbia Electricity Price
Index (Dow Jones Mid-C Index).
On June 14, 2019, PacifiCorp submitted an application to close Electric Service Schedule 135
and to implement a net billing program to compensate customer-generators for exported
generation.3 On August 26, 2020, the Idaho Public Utilities Commission issued Order No. 34753
which required this on-site generation study to be completed. On October 2, 2020, the Idaho
Public Utilities Commission issued Order No. 34798 initiating Electric Service Schedule 136 - Net

3 See In the Matter of the Application of Rocky Mountain Power to Close the Net Metering Program to New Service
& Implement a Net Billing Program to Compensate Customer-Generators for Exported Generation. Case No. PAC-E-19-08
0
500
1000
1500
2000
2500
On-Site Customer Count
Irrigation
Large Commercial
Small Commercial
Residential

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Billing Service. Order No. 34798 also adopted Order No. 34752, which granted existing Electric
Service Schedule 135 customers grandfathered status for a period of 25 years.
3.0 Netting Period
3.1 Summary of Instantaneous, Monthly, and Hourly Billing
There are three different methods of “netting” that may be used to calculate the amount of
electricity that a customer consumes and exports: instantaneous, hourly, and monthly. In a
“real time” or “instantaneous” calculation, the metered quantities of electricity that are
exported to the grid form the customer’s generator and that are taken from the grid and used
are measured separately. With instantaneous netting, all of the consumption from the electric
grid is measured and charged the retail rate and all exports to the electric grid are also
measured and credited to the customer.
Interval netting, on the other hand, does not calculate instantaneously but instead calculates
the total net electricity consumed or generated over the certain interval or period of time.
While on first look it may appear that instantaneous and interval netting would result in similar
outcomes, this is not the case. To the extent a customer was using power from the electric grid
during part of an hour, and exporting during the rest of an hour, hourly netting would wash out
these two amounts, relative to instantaneous netting. With monthly netting, even larger
amounts of consumption and exports can be offset, as the customer’s consumption may be
days or weeks earlier or later than their exports.
Using an interval over which exports and imports are netted masks the actual timing of energy
delivered to the customer and energy exported from the customer and distorts the service that
Rocky Mountain Power provides. One benefit of a net billing program without interval netting is
that it encourages customer-generators to line up their usage with their generation output. This
can benefit other non-participating customers by accurately taking into account the load that
the customers with generation draw from the system. Netting over an interval period, such as
15 minutes or an hour, provides less of an incentive for customer-generators to match usage
with generation. With the scale of customer generation that has been adopted in the Company’
service territory, encouraging loads to line up with intermittent generation has never been
more important. When a cloud rolls by an area where there is a lot of customer generation,
their energy generation will suddenly drop, and the Company must provide the power needed.
Indeed, every fraction of a second the Company must serve the load requirements of its
customers as loads fluctuate in real time. Strongly encouraging customer generators to line up
their generation with load as a net billing program does, creates a greater opportunity for
customer-generators to benefit the system.
3.2 Class Revenue Requirement
The tables and analysis below address Study Scope Item 1.

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Study Scope Item 1
their energy exports:
a. Monthly
b. Hourly
c. Instantaneously

To estimate the revenue requirement impact to revenue for each of the types of netting
required for the Study, the Company examined the monthly billing and metering data from
customer-generators in 2022 from which the Company could determine values for the monthly
netting and instantaneous netting scenarios. The Company did not include irrigation customer-
generators, because there were only two irrigation customers with on-site generation, and they
did not have a full 12 months of revenue in 2022.
Automated meter infrastructure (“AMI”) installations are being finalized during the second
quarter of 2023 and the Company does yet not have enough hourly profile data available for
customer-generators in Idaho for hourly loads. Instead, the Company used proxy profile data
from its customer-generators in northern Utah which are in the same climate zone as the
Company’s Idaho service territory. To estimate hourly netting values, the monthly percentage
differences in hourly as compared to instantaneous netting from the Northern Utah dataset
were applied to metered data from Idaho customer-generators. The following table 3.1 shows
the exported energy volumes under each netting scenario in total and also expressed as a
percentage of generation:

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Table 3.1: Comparison of Generation to Exports under Different Netting Scenarios
(kWh) Netting Netting Netting
2,111,780 8,062,620 8,554,724 16,422,970
551,492 2,058,027 2,182,649 4,124,398
244,599 534,099 565,335 1,512,638
58,760 116,414 123,320 522,963

Netting Netting Netting Generation
13% 49% 52% 100%
13% 50% 53% 100%
16% 35% 37% 100%
11% 22% 24% 100%

Table 3.1 shows that about half (51%) of generation is exported to the grid. If exports are
netted on an hourly basis, exports are a little less at about 48% of generation. Using monthly
netting, dramatically reduces the quantity of exported energy to being only about 13% of
generation. To estimate the revenue impact by customer class of different netting scenarios,
the Company estimated the change in revenue from traditional net metering. Assuming a
generic 3¢ per kWh export credit, the Company estimates the following revenue changes from
traditional net metering for the different netting scenarios:

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Table 3.2: Revenue Requirement Changes from Traditional Net Metering
Netting Netting Netting Net Metering
$1,253,784 $1,716,364 $1,756,739 $1,090,937
$384,917 $462,434 $468,933 $333,476
23
$156,402 $172,883 $174,728 $141,635
6
$296,204 $296,925 $297,011 $295,469
Schedules)
$2,091,307 $2,648,606 $2,697,411 $1,861,517
Traditional Net
Metering
-$229,791 -$787,089 -$835,895 -

Based on Table 3.2 above, monthly netting would result in a $230k increase to revenue when
compared with traditional net metering, meaning that an additional $230k is recovered from
customer generators and not required from other customers. Hourly netting would see a larger
$787k increase and instantaneous netting would see a $836k increase in revenue when
compared with traditional net metering.
3.3 Class Export Payment
The Study Scope also required the Company to calculate the export credits for each customer
class at different intervals.
Study Scope Item 2
net their energy exports:
a. Monthly
b. Hourly
c. Instantaneously

Using the same assumptions as the revenue analysis above, the Company estimates the
following class export payments for the different netting scenarios.

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Table 3.3: Export Payments by Class
Netting Netting Netting
$63,353 $241,879 $256,642
$16,545 $61,741 $65,479
$7,338 $16,023 $16,960
$1,763 $3,492 $3,700

3.4 Bill Impacts
The Study Scope required the Company to calculate the bill impacts to existing customer-
generators.

Study Scope Item 3
netted:
a. Monthly
b. Hourly
c. Instantaneously

Using the same assumptions from the previous sections, the Company estimates the following
average bills for the different netting scenarios:

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Table 3.4: Bill Impacts by Class
Netting Netting Netting Net Metering
$14.49 $44.44 $47.28 -$2.66
$77.92 $97.97 $99.38 $77.49
$128.66 $144.73 $145.83 $128.55
$179.33 $193.98 $194.99 $179.33
$247.76 $261.38 $262.37 $247.76
$372.39 $383.30 $384.07 $372.39
$624.67 $632.67 $633.28 $624.67
$2,553.63 $2,559.70 $2,560.04 $2,553.63

3. 5 Administrative Costs
Instantaneous billing provides administrative benefits compared to interval netting. Under
instantaneous netting, all exported energy sent to the grid is measured and all energy delivered
from the grid to the customer to be used at their site is measured. These are two simple
quantities of energy that the meter shows each month. Under interval netting, such as hour
interval netting, these measurements must be examined and netted for every hour. Using the
meters for exported and delivered energy instead of relying upon profile data (for example
hour-by-hour usage measurements in a month) to bill customers is less administratively
burdensome for the Company. Without netting, the Company’s meters simply record energy
delivered and energy exported and send those amounts to the Company’s billing system to
calculate a bill for the customer. While the Company has automated much of the process for
billing customers based upon 15-minute intervals for customer generators in Utah, there still is
some backend manual work that is required to accurately bill customers. 15-minute interval
netting requires much more data for each meter which on average includes 2,920 reads for
each monthly billing period. Most of the time, there are no issues with this data, but when
there is, Company employees must resolve it. Some of the issues that may require employee
attention include:
• Meter aggregations require manual calculation using a billing calculation sheet. The
Company estimates 0.25 – 0.50 hours per month aggregating meter data depending on
number of meters involved.
• Interval data issues such as from gaps in data or when meters are exchanged also
require employee time. It is hard to estimate the time spent on missing data as it only
occasionally happens and now AMI exchanges are mostly complete in Idaho. Going
forward, meter exchanges will happen less frequently. Assuming a one percent failure

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of billings each year and 0.5-1.0 hours to resolve for each 100 customers in net billing,
then the following time requirement is estimated:
100 customers x 12 billings = 1200 x 1% = 12 accounts x 0.5 – 1.0 hour = 6
- 12 hours annually
At the current volume of 2,200 customer-generators, this would be about 132 to 264 hours of
activity per year for the Company. In addition, using total exported energy and total delivered
energy in the billing calculation is a simpler concept to explain to customers than netting over
each 15-minute or hour interval. It is much easier for someone to understand that all energy
sent to the grid will get a certain export price and all energy delivered to the customer will be
billed at standard tariff rates than to describe how energy is netted in every interval period.
4.0 Export Credit Rate
The ECR determines the total credit to the customer once a customer’s generation is netted by
either instantaneous netting or interval netting. The ECR is calculated by looking at the costs
the Company avoids from exported energy. These costs are broken into five parts:
• Avoided Energy Costs
• Avoided Capacity or Generation Costs
• Avoided Fuel Risk Costs
• Avoided Transmission and Distribution Costs
• Avoided Line Losses
Once all the costs from the parts listed above are combined, they are adjusted to account for
the costs incurred by integrating the generation into the system. A summary of these costs by
component is provided in table 4.1 below, and descriptions of each component are provided in
the following sections. Note that these values have not been adjusted to reflect the reduced
value of non-firm deliveries, as discussed in Section 4.3.2.

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Table 4.1: Summary of Export Credit Costs
¢/k
Wh Energy
Value
(Forecast)
EIM
Energy
Value
(Actual
Risk
Value Capacity Trans
Capacity
Capacity Losses ation
Cost
Export
Credit
4.08 2.83 0.00 0.00 0.06 0.16 0.30 -0.02 4.57
3.38 4.35 0.71 0.00 0.06 0.16 0.30 -0.02 4.58
3.25 0.51 0.00 0.06 0.16 0.28 -0.61 3.66
1.99 0.08 0.00 0.06 0.17 0.16 -0.19 2.27
2.03 0.03 0.00 0.05 0.15 0.16 -0.12 2.30
2.01 0.02 0.66 0.05 0.12 0.21 -0.09 2.97
2.12 0.02 0.54 0.04 0.10 0.20 -0.24 2.79
2.34 0.03 0.42 0.03 0.08 0.21 -0.23 2.87
2.84 0.02 0.42 0.03 0.08 0.24 -0.04 3.59
2.99 0.02 0.42 0.03 0.08 0.25 -0.05 3.74
3.07 0.02 0.31 0.02 0.06 0.25 -0.02 3.70
3.16 0.02 0.19 0.01 0.04 0.24 -0.03 3.64
3.18 0.02 0.19 0.01 0.04 0.24 -0.01 3.68
3.34 0.02 0.19 0.01 0.04 0.26 -0.01 3.85
3.47 0.02 0.20 0.02 0.04 0.27 -0.01 4.00
3.80 0.02 0.20 0.02 0.04 0.29 -0.01 4.35
4.43 0.03 0.18 0.01 0.04 0.33 -0.005 5.01
5.22 0.10 0.15 0.01 0.03 0.39 -0.005 5.90
5.68 0.09 0.12 0.01 0.03 0.42 -0.005 6.34
5.53 0.11 0.10 0.01 0.02 0.41 -0.03 6.14

4.1 Modeled Data as an Estimate for Actual Customer Export Data
In relation to using modeled data as an estimate for actual customer data, the Study Scope
asked for a date when a full year of hourly AMI export data will be available.
Study Scope Item 4
Confirm when a full year of hourly AMI export data will be available for customer-generators.

As of April 27, 2023, deployment of AMI meters in Idaho is 97 percent complete. A full year of
hourly AMI export data for Idaho customers for nearly all customer-generators will be available
one year from this date.

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4.2 Model Validation Method
The Study Scope required the Company to explain its method for verifying and validating the
accuracy of its model and modeled customer data.
Study Scope Item 5
Explain the Company’s method for verifying and validating the accuracy of its model and
modeled customer export data.

As detailed in the discussion of the netting period, the estimate of hour-by-hour exported
energy quantities were calculated using the data from all customer-generators taking service
on Schedule 136 in northern Utah that are in the same climate zone as the Company’s Idaho
service territory.
While the Company maintains a sample of hourly information for Idaho customer-generators,
the information taken from Utah customers in northern Utah is more suited for this Study for
several reasons. First, the Idaho customer generation sample was put in place in 2014 and
taken from a group of very different customers than what we see today. Roughly one-half of
the generation systems in the 2014 Idaho sample were wind; however, most customer-
generator systems are now operating solar PV. Second, the Idaho customer generation load
research sample includes 44 sites and may not be a good sample. A sample this size produces
estimates with sampling errors of 10 to 20 percent. Estimates taken from all northern Utah
customer generators do not have the same sampling error. Finally, the Company’s northern
Utah and Idaho service territories have similar climates and geographic characteristics. The
Company used the International Energy Conservation Code (IECC) climate zone map to identify
Utah customers in climates similar to that of the Company’s Idaho service territory.4 Nearly all
Idaho customers are in climate zone 6B. The Company identified Utah customers taking service
on Schedule 136 also in climate zone 6B and calculated average hour-by-hour export quantities
from these customers (“Northern Utah Customers”).
To validate the accuracy of hourly export information taken from all of the Company’s Northern
Utah customer generators, the Company first reviewed sources of statistical error and bias.
Sampling and measurement error are two major sources of statistical error. By definition,
estimates taken from all customers are not subject to sampling error. Measurement errors are
small—the Company purchases meters with accuracy certified by the manufacturer to be in
compliance with the American National Standard Code for Electricity Metering (ANSI C12.1).
The Company also examined sources of bias. Estimates are biased if the group of customers
being studied (in this case Idaho customer generators) is systematically different from the
sample group (in this case customer generators in Northern Utah) used to represent that group

4 See the 2021 International Energy Conservation Code (IECC) “Section C301 Climate Zones” for a map and a list of
climate zones for each county. Counties in the Company’s Idaho service territory are in climate zone 6B (cold and
dry). https://codes.iccsafe.org/content/IECC2021P1/chapter-3-ce-general-
requirements#IECC2021P1_CE_Ch03_SecC301

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being studied. Possible systematic differences and sources of bias between these two groups
include:
Differences in solar photovoltaic system sizes: If customer demand were otherwise
equal, a larger solar photovoltaic system size would result in a greater portion of the
total generation of the system being exported to the grid, and smaller portion used
onsite.
Differences in actual monthly exports and deliveries: Building size and the types of load
the customer has can contribute to differences in total customer demand, which could
cause a difference in actual monthly exports and deliveries. Higher total usage, with the
same generation, would result in lower exports.
Different amounts of solar irradiance (how intense the sunshine is) and PV generation
in the two regions: Idaho customer-generators are concentrated primarily in counties
surrounding Idaho Falls. This is 150 miles north of Logan, Utah, where most of the
Northern Utah Customers are concentrated. Geographic differences could produce
different levels of solar irradiance and PV generation.
The Company first compared the installed capacity of customer generation systems of Northern
Utah Customers and Idaho to determine if there was a systematic difference in system sizes.
The Company found a small difference in system sizes—the installed capacity of Idaho
customers’ systems is 5.2 percent lower than the capacities of Northern Utah Customers. Table
4.2 presents the mean installed capacity for each of these groups.
Table 4.2: Northern Utah Customers and Idaho System Size (Installed Capacity)5
Population Installed Capacity (kW)
Average Northern Utah Customers
Average Idaho
Percent Difference -5.2%

Next, the Company compared actual average monthly deliveries and exports from Idaho
customer-generators against Northern Utah Customers in 2022. The distribution of exports
across months for Idaho and Northern Utah Customers is similar as shown in Table 4.3 and
Figure 4.1.6

5 Supporting data provided in Appendix 4.4: Idaho Export Profile Validation Avg Capacity
6 Supporting data for Table 4.3 and Figure 4.1 provided in Appendix 4.5: ID Export Profile Validation Monthly
Exports

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Table 4.3: Northern Utah Customers and Idaho Average 2022 Monthly Exports
139 95 2% 2%
375 199 6% 3%
426 412 7%7%
Apr
May 677 644 11%11%
Jun 804 776 13%13%
Jul
Aug
Sep 575 651 9%11%
Oct
Nov 434 383 7%6%
Dec 189 143 3%2%
Total 6,136 5,980 100% 100%

Figure 4.1. Northern Utah Customers and Idaho Monthly Exports Comparison

The Company found that Idaho customers exported slightly less than Utah customers in winter
and shoulder (Fall and Spring) months, while exporting more in summer months. The weighted
average absolute difference in monthly exports between Idaho and Northern Utah Customers is
about 11 percent (weighted by monthly exports).
Finally, the Company used estimated solar PV generation information to compare the hourly
shape of systems in Idaho against those customers located in Utah climate zone 6B. This
involved first determining the areas where there are customer-generators in Utah climate zone

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6B and in Idaho. Sixty-nine percent of all the customer generation capacity in Idaho is
concentrated in the counties surrounding Idaho Falls including Bonneville (37 percent),
Jefferson (20 percent), and Madison (12 percent) counties. In Utah climate zone 6B, counties
near Logan; Cache (33 percent), Summit (28 percent), and Box Elder (20 percent), are about 82
percent of the installed capacity.
The Company used the National Renewable Energy Laboratory’s PVWatts7 calculator to
estimate the hourly solar PV generation for a typical system located in Idaho Falls, ID and
Logan, UT. PVWatts is a publicly available online calculator that estimates the amount of
electricity generated by a typical solar PV system..
For each location, the Company estimated the hourly output of an 8 kW solar PV system. The
Company then calculated each location’s solar PV generation by month. The Company then
summarized this information into averages for 12-month by 24-hours and calculated the
Weighted Mean Absolute Percentage Error (“wMAPE”), a statistical test, between the Idaho
and Utah production profiles for each time interval. To understand the total difference across
months and the hourly difference within months, two versions of wMAPES were calculated:
Monthly Weighted Mean Absolute Error: This statistic captures differences in the total
Utah and Idaho values across months. If one location produces more than another in a
specific month, this wMAPE will be higher for that month.
Hourly Weighted Mean Absolute Error: This statistic measures the difference between
Idaho and Utah hourly production profiles within months. It compares the average 24-
hour shape for each month, ignoring differences in production across months. If solar
PV systems in one location produce more later in the day than the other, these wMAPEs
will be higher.
Table 4.4 shows the wMAPES for each month from the monthly and hourly perspectives.
Months with higher monthly wMAPEs have a larger difference in both total solar PV generation
for the month and across hours within the month. Months with higher hourly wMAPEs exhibit
differences in 24-hour shapes (ignoring differences across months).
Winter months exhibit the greatest errors, which reflect both differences in location and the
number of sunny days. This finding is similar to the prior comparison of monthly exports.
Overall, the wMAPEs are 7.9% across the year and 5.4% within months.

7 See https://pvwatts.nrel.gov/

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Table 4.4: Solar Production Difference - Weighted Mean Absolute Percentage Errors8
Percentage error Percentage Error
18.7% 14.0%
8.7% 9.5%
4.6% 4.7%
7.7% 3.9%
8.3% 7.4%
7.5% 3.5%
5.0% 2.4%
5.7% 4.7%
5.2% 3.9%
5.3% 3.9%
14.8% 8.3%
26.5% 13.8%

The Company concludes from this analysis:
• System sizes for Idaho customer-generators are like those of Northern Utah Customers.
The Company found that the Idaho systems have installed capacities that are
approximately 5 percent lower than northern Utah systems.
• Winter months show a larger difference in total solar PV generation (greater than 10
percent wMAPE).
• Within months and across hours, the difference between the Logan, Utah and Idaho
Falls, Idaho generation shapes is small—mostly less than 10 percent, on average.
The Company expects that differences in hourly export shapes between Northern Utah
Customers and Idaho will be like the differences found in the Logan and Idaho Falls generation
shapes. While the Company expects a greater difference in exports in the winter months and a
smaller difference in the summer months, its analysis indicates that the overall difference will
be small.
4.3 Avoided Energy Value
The Study Scope requested the avoided energy value be calculated using the energy price
assumptions in the Company’s most recently acknowledged IRP.

8 Supporting data provided in Appendix 4.6: ID Export Profile Validation PV Watts Production

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Study Scope Item 6
Calculate the avoided cost of exported energy using the energy price assumptions in the
Company’s most recently acknowledged Integrated Resource Plan (“IRP”).

The Commission acknowledged the Company’s 2021 IRP in August 2022. The 2021 IRP included
a variety of price and policy scenarios, with the main scenario including a medium gas price
forecast and medium greenhouse gas costs. These assumptions are a part of the hourly market
price forecasts, based on input assumptions used in the Company’s September 2020 official
forward price curve. Within the IRP models, energy value varies by location because of limits in
transmission and the balance of supply and demand. As a result, energy value in the Company’s
Idaho service territory will vary from the price at distant market points. With that in mind, for
the purpose of calculating the energy value and cost-effectiveness of energy efficiency
measures, the Company uses hourly marginal resource costs reported by its IRP models.
The Company notes that energy price assumptions in the 2021 IRP will be three years out of
date in September 2023.
The Company also notes that the forecast wholesale prices used in the IRP may not be the best
way to actually capture the value of customer generation exports. Specifically, customer
generation exports will tend to be lower when customer load is high because a greater portion
of the customer’s generation can be devoted to the customer’s own usage needs under those
conditions. If, for example, the customer’s load is high because of effects that impact the
system as a whole, such as regional weather conditions like a heat wave, this would cause
lower exports when demand and energy costs are highest. This situation where exports are
lower during times of peak load times is not captured in the forecast modeled using 2021 IRP
results, but it is present in after the fact historical data. An alternative to using IRP information
that captures this situation is using actual Energy Imbalance Market (“EIM”) prices to value
customer generation exports by each hourly period. Because EIM prices are public, do not
require complicated forecasts or models, and more accurately capture the real conditions of a
historical time period, they can be a good option for calculating energy value. Energy values
based on 2021 IRP results and historical EIM prices are presented in Table 4.1.
4.3.1 Supporting Documentation for Avoided Energy Value
The Study Scope requested the supporting documentation for the Company’s avoided energy
value calculation.
Study Scope Item 6(a)
Provide supporting documentation.

The 2021 IRP energy values shown in Table 4.1: Summary of Export Credit Costs shows the
value of customer exports using the hourly incremental energy prices for the Goshen, Idaho

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location from the Company’s 2021 IRP preferred portfolio results, which were also used for the
Idaho energy efficiency cost-effectiveness evaluation. The EIM energy values shown in Table 4.1
reflect the value of customer exports using average hourly historical EIM prices in the Real-Time
Pre-Dispatch market (15-minute market) for the PacifiCorp East Load Aggregation Point location
(a weighted average for load points in PacifiCorp’s East Balancing Authority Area).
4.3.2 Supporting Documentation for Non-Firm Energy
The Study Scope requested the Company provide calculations and documentation showing why
the avoided cost of exported energy produced by customer-generators should be valued at 85%
of the total avoided energy value.
Study Scope Item 7
Provide the calculations and documentation showing why the avoided cost of exported
energy produced by customer-generators should only be valued at 85% of the total avoided
energy value.

Customer-generators are non-firm energy, meaning that there is no guarantee that exported
energy will be delivered to the grid at specific times. Commission practices for pricing qualifying
facilities (“QF”) value non-firm energy deliveries at 85% of the total avoided energy value.
Because customer-generators make no commitment to export particular quantities of energy to
the grid, they are considered non-firm energy. An 85% adjustment is similar to current practices
for both the surrogate avoided resource (“SAR”) methodology when pricing qualifying facilities
and for the customer generation net billing credit for PacifiCorp customers taking service on
Schedule 135.9
However, the SAR Methodology does have some limitations since it does not have hourly detail.
Using EIM prices for the avoided energy value may be preferrable since it can better value
customer exports in particular hours. Because EIM prices are set shortly before the time of
delivery, they do not have the same risk as firm delivery commitments made in advance and
may not require as large of a non-firm adjustment. EIM prices are also public, which allows for
greater transparency, and they can better reflect the value of export timing than a forecast.
Idaho Regulatory History of SAR Methodology and Non-Firm Energy Pricing
The Commission has approved the SAR Methodology for determining avoided costs for
standard qualifying facility resources up to at least 100 kW in nameplate capacity. Under the

9 In addition to the 85 percent adjustment made for non-firm energy under the SAR Methodology, Schedule 135’s
Net Metering Rate Credit for non-residential customers is calculated at 85 percent of the monthly weighted
average of the daily on-peak and off-peak Mid-Columbia Intercontinental Exchange Electricity Price Index (Mid-C
ICE Index) prices for non-firm energy.

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SAR Methodology, avoided energy costs reflect forecast prices for natural gas and the assumed
heat rate of a combined cycle combustion turbine. 10
In Order No. 29632, the Commission found that energy “delivered outside of the 90/110
performance band (i.e., non-conforming energy) would be priced at 85 percent of the non-firm
market price or the contract price, whichever is less.”11 The non-firm market price has been
found by the Commission to equal to the 82.4 percent of the firm market price.12 Based on the
this, the formula for non-firm energy delivered outside the performance band for qualifying
facilities is below:
Non-firm market price outside of performance band = 85% * non-firm market price; where
Non-firm market price = 82.4% * firm market price
Firm Energy and Non-Firm Energy
To better understand how the customer-generators differ from firm wholesale energy
purchases or sales, it is helpful to understand some key aspects of firm wholesale energy
transactions. At present, most firm wholesale energy transactions reflect a limited set of
market products such as:
• Blocks of hours at a constant amount, typically Heavy Load Hours (HLH), Light Load
Hours (LLH), or all hours.13
• Monthly products (covering every day in a month) are available prior to the start of a
month, while transactions for individual days are only available a day or two before
delivery.
• Typically traded in in blocks of 25 MW.
• Only a few locations have many buyers and sellers, such as Mid-Columbia or Palo Verde.
There is a small number of buyers and sellers at most locations, and those buyers and
sellers may not be interested in buying or selling a specific product.
• Such market products are considered firm because the seller is subject to costs for
damages if it fails to provide deliveries as agreed.
Exports from customer-generators are very different from wholesale energy products.
Customer-generators exports:

10 In the Matter of the Commission's Review of PURPA QF Contract Provisions Including the Surrogate Avoided
Resource and Integrated Resource Planning Methodologies for Calculating Avoided Cost Rates, Case No. GNR-E-Il-
03, Order No. 32697 at 7-8 (Dec. 18, 2012).
11 In the Matter of Rocky Mountain Power’s Application for Approval of Power Purchase Agreement between
PacifiCorp and Birch Hydro Company, Case No. PAC-E-20-07, Order No. 34889 at 2 (Jan. 14, 2021).
12 In the Matter of Rocky Mountain Power’s Application for Approval of Power Purchase Agreement between
PacifiCorp and Birch Hydro Company, Case No. PAC-E-20-07, Order No. 34889 at 2 (Jan. 14, 2021).
13 HLH is 6:00 a.m. to 10:00 p.m. (Pacific Prevailing Time) Monday through Saturday, excluding certain holidays.
LLH is all other hours, namely 10:00 p.m. to 6:00 a.m. nightly, and all day on Sundays and holidays.

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• Vary from moment to moment.
• Are not committed in advance.
• Are not delivered to major energy market locations.
• Provide no commitment to deliver. A customer may not have excess power to sell back
to the utility, either because its generation is low or because its own energy usage is
high.
A utility must provide energy equal to its customer load at all times. Both its supply of energy
and loads are uncertain, as wind and solar generation output varies, load varies, and other
sources of generation experience unplanned outages. Under nearly all conditions, a utility must
have sufficient energy supply to balance its loads with enough extra energy to meet its
reliability obligations.
Since the amount of exported energy sent to the grid may be different than expected, a utility
must adequate energy supply to serve load. Such energy supply cannot support firm wholesale
energy market sales if the amount of exported energy is less than expected, because such sales
would need to be finalized at least a day in advance, if not longer. In addition, if the utility’s
energy supplies are only available for a few hours, they may not be able to support the entire
duration and quantity of a market product (such as during the heavy load hour block of time or
all day as discussed above in this report).
The difference in value between a firm market transaction and non-firm energy varies based on
a variety of factors, including the hourly timing of non-firm energy, the supply and demand
expectations of wholesale energy market buyers and seller, and the uncertainty in supply and
demand, along with the next best alternatives for wholesale energy market buyers and sellers.
With the advent of EIM, significantly more market data is available that better matches up with
the timing of exported energy. EIM prices reflect:
• Shorter periods of time (five or fifteen minutes).
• Energy delivery begins a few minutes after a dispatch instruction is received.
• No minimum quantity.
• Location-specific values for large scale energy resources, or values specific to
PacifiCorp loads.
While no single wholesale energy market price can reflect the intertwined month-ahead, day-
ahead, hour-ahead, and intra-hour planning and operations used to balance PacifiCorp’s load
and energy supply, EIM prices can be a better estimate of the actual value of customer exports.
4.4 Avoided Capacity Value
The Study Scope requested the Company analyze the capacity value of exported energy
provided by customer-generators using either the LOLP study or by evaluating the amount of

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power exported to the grid by customer-generators during the top 100 peaking events in the
last 10 years.
Study Scope Item 8
8. Analyze the capacity value of exported energy provided by customer-generators on a class
basis using one of two methods:
a. Loss of Load Probability Study, or
b. Determine the power that is reliably exported to the grid by net metering during
peaking events. Use the top 100 peaking events from each of the past 10 years (1,000
peaking events). Use a reliability threshold of 99.5%. If, for example, the study determines
that customer-generators provide no less than 1.5 MW of power during 99.5% of the
peaking events, then use 1.5 MW as the basis for determining the capacity avoided by the
customer-generator class.

The Company has examined the capacity value of exported energy using the loss of load
probability (LOLP) study from its IRP. The Company also looked at the top 100 peaking events
from the past two years.
4.4.1 Loss of Load Probability Study
The Company’s LOLP study from its 2021 IRP, is used to estimate the amount of capacity that
customer generation exports provide. The study is discussed in the 2021 IRP in Volume II,
Appendix K: Capacity Contribution14.
The capacity factor approximation methodology described as the “CF Method” in Appendix K of
the 2021 IRP can be used to estimate the amount of capacity a particular hourly amount of
energy can provide from the LOLP results. The CF Method calculates the amount of capacity
provided based on the expected availability of energy during times when the risk of loss of load
is highest (the LOLP in each hour).
The Company calculated the amount of capacity provided from exported energy in the last two
years (2021-2022) by month and hour (a “12x24 profile”), i.e. assuming that customer exports
were neither higher, nor lower, than average during hours with LOLP. Figure 4.2 below shows
the hours with higher LOLP shaded in red:

14 Included with this Study as Appendix 4.7: Appendix K - Capacity Contribution - 2021 IRP

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Figure 4.2: Weighted LOLP Distribution

As shown on Appendix 4.2: Export Credit Calculation, this results in the amount of capacity
being provided from exported energy equal to 3.0% of their nameplate capacity, prior to
accounting for avoided line losses. By comparison, the 2021 IRP identified that this value is 13%
for large scale solar energy generation in Idaho. One of the key differences is that customer
generation exports are sent to then grid after a customer uses the generation at its site. Large
scale solar generation is also different, because it uses tracking technology where the panels
are tilted to follow the sun throughout the day, which increases its generation in the morning
and evening when LOLP is higher.
The LOLP distribution shown in Figure 4.2 reflects the timing of risks associated with the 2021
IRP preferred portfolio in calendar year 2030. These risks will evolve as the underlying portfolio
changes, for example, risks during the day tend to diminish as more solar resources are added.
Similarly, the risks during the day may increase if a portfolio is more reliant upon short-duration
resources, like energy storage or demand response. The capacity contribution from exported
energy is expected to drop from 6.8% in 2024, to 3.0% in 2030, and to 1.3% by 2036 as a result
of the changing composition of the 2021 IRP preferred portfolio through time. This projection
of capacity value through time has been incorporated in Table 4.1.
4.4.2 Historical Peak Conditions
The Company has compared historic customer generation exports and the top 10 percent load
times over the past two years, spanning 2021-2022. During all hours in the top 10 percent of
annual Idaho load, exports provided an average of 12.7% of its maximum generation, while
during all hours in the top 10 percent of annual PacifiCorp system load, exports provided an of
14.4% of its maximum generation. Many of the top hours have significantly lower exports, as
shown in Table 4.5 below. Much less than 1% of maximum generation is available for more than
99.5% of top hours.15

15 Data for analysis provided in Appendix 4.1: Export Profile Jan21-Dec22.

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Table 4.5: Customer Generation Exports During Peak Loads
Load
4.73% 0.58% 0.0387% 0.0097% 0.0020% 0.0013% 0.0005% 0.0002%
9.98% 4.29% 0.9985% 0.0460% 0.0110% 0.0042% 0.0012% 0.0005%

These results only look at top load hours and do not account for reliability and risk that is
related to energy supply. The 2021 IRP results account for periods when loads are high and
energy supply availability is low. Energy supply availability is particularly important as solar
generation is becoming a greater share of PacifiCorp’s energy supply. As a result, the added
reliability benefits from customer generator exports (which are primarily solar) are reduced.
4.4.3 Time-Differentiated Capacity Values
The Study Scope requested the Company provide hourly time-differentiated capacity values.
Study Scope Item 9
Provide hourly time-differentiated capacity values.

PacifiCorp has calculated hourly generation, transmission, and distribution capacity values (in
$/MWh) based on the 2021 IRP LOLP capacity analysis described above. Hourly capacity values
were assigned by the LOLP by month and time of day shown in Figure 4.2. Beginning in June
2025, the on-peak period for the residential time of day option Schedule 36 will be all days from
3 p.m. to 11 p.m. during the months of June through October and 6 a.m.to 9 a.m. and again
from 6 p.m. to 11 p.m. during the months from November through May. In a future net billing
program, the capacity value of the export credit could be given a higher value during these on-
peak hours and a lower value during off-peak hours. Table 4.6 below shows the year-by-year
capacity values that are shown on Table 4.1 but broken out by on-peak and off-peak time
periods and by season. Note that each of the four time of use period definitions shown result in
the same compensation for a customer whose exports align with the average export profile.
Customers who are able to export more during on-peak and/or summer periods would receive
higher compensation with differentiated rates.

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Table 4.6: Capacity Value by Time of Use Period
Year All Hours On-Peak Off-Peak
0.21 1.32 0.06 0.47 0.03 1.57 0.12 0.07 0.02
0.22 1.35 0.06 0.48 0.03 1.60 0.12 0.07 0.02
0.22 1.38 0.06 0.49 0.03 1.63 0.12 0.07 0.03
0.23 1.41 0.06 0.50 0.03 1.67 0.12 0.07 0.03
0.20 1.21 0.06 0.44 0.02 1.44 0.12 0.06 0.02
0.83 4.87 0.26 1.83 0.09 5.78 0.56 0.26 0.09
0.68 3.83 0.24 1.51 0.07 4.54 0.54 0.21 0.06
0.53 2.75 0.21 1.18 0.05 3.26 0.51 0.17 0.04
0.53 2.34 0.27 1.11 0.10 2.73 0.59 0.33 0.09
0.53 1.91 0.34 1.03 0.16 2.18 0.67 0.51 0.15
0.39 1.52 0.23 0.80 0.09 1.76 0.49 0.29 0.08
0.24 1.12 0.12 0.55 0.01 1.33 0.30 0.06 0.01
0.25 1.06 0.13 0.55 0.02 1.25 0.32 0.10 0.02
0.25 1.00 0.14 0.54 0.03 1.17 0.34 0.14 0.03
0.25 0.93 0.16 0.53 0.05 1.08 0.36 0.17 0.04
0.26 0.86 0.17 0.52 0.06 0.99 0.38 0.21 0.05
0.23 0.90 0.13 0.40 0.10 0.75 0.29 1.68 0.04
0.19 0.95 0.09 0.27 0.14 0.51 0.19 3.19 0.03
0.16 0.99 0.04 0.14 0.18 0.26 0.10 4.73 0.01
0.13 1.04 0.00 0.00 0.22 0.00 0.00 6.31 0.00

4.5 Avoided Risk
The Study Scope requested the Company evaluate avoided risk by examining whether there is a
fuel price guarantee value provided by on-site generators as a class.
Study Scope Item 10
Analyze whether there is a fuel price guarantee value provided by on-site generators as a
class.

PacifiCorp’s 2021 IRP included statistical analysis, which examined costs considering variations
in load, hydro generation output, electricity and natural gas prices, and unexpected outages of
thermal generators. PacifiCorp’s calculation of the energy value and cost-effectiveness of
energy efficiency measures used these results to identify the additional value associated with
these risks. PacifiCorp has calculated the avoided risk value for customer exports using the

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same risk values that were used for energy efficiency. Over the time period for the 2021 IRP,
the risk value increases the energy value for customer exports by 3.9%, or $1.24/MWh as
shown on summary tab of Appendix 4.2: Export Credit Calculation.
5.0 Project Eligibility Cap
An evaluation of the pros and cons of setting a customer’s project eligibility cap at different
predetermined caps and demand levels was requested by the Study Scope.
Study Scope Item 11
Analyze the pros and cons of setting a customer’s project eligibility cap according to a
customer’s demand as opposed to predetermined caps of 25 kW and 100 kW.
a. Analyze at 100% of demand.
b. Analyze at 125% of demand.

Per the estimated load information used in the Company’s last general rate case16, the
estimated maximum peak is 8.4 kW for the typical residential customer taking service on
Schedule 1 and 11.5 kW for the typical residential customer taking service on Schedule 36. At
25 kW, the current cap is well above 125 percent of the typical customer’s demand. Setting a
capacity level that is based upon an individual customer’s demand could be administratively
burdensome and could create frustration for smaller customers who want to install a larger
facility. It could also encourage customers to have a higher peak load before they request to
interconnect an onsite generation system. The complications of setting a capacity level based
on the individual customer’s demand would be the same at 100% of demand and at 125% of
demand. For residential customers, the benefits of a generic 25 kW cap is that it is
administratively simple, easy for customers to understand, does not encourage a customer to
increase its demand, and is set at a level that is well above the maximum demand for the
typical customer. The downside of a generic cap is that it might be too large for smaller energy
users causing them to unnecessarily oversize their system and conversely might be too small for
very large users and not provide enough capacity to meet their energy needs.
For non-residential customers, the pros and cons of a generic 100 kW cap are the same as for
residential customers for smaller users. For larger users, a 100 kW cap may be significantly less
than the level that would be needed to meet their annual energy needs. However, a larger user
can become a qualifying facility and be compensated for their generation output at an avoided
cost rate. Avoided cost pricing for qualifying facilities is more accurate since it is set for specific
technologies (i.e. wind, fixed tilt solar, tracking solar, and baseload) and takes into

16 In the Matter of the Application of Rocky Mountain Power for Authority to Increase its Rates and Charges in
Idaho and Approval of Proposed Electric Service Schedules and Regulations. Docket No. PAC-E-21-07

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consideration whether the customer wants to provide on a firm17 or non-firm basis. A
downside of becoming a qualifying facility can be that it is a more onerous process for a
customer to interconnect. Table 5.1 below shows the pros and cons of using a generic cap
versus using a multiple of the customer’s actual demand to set an individualized cap:
Table 5.1: Pros and Cons of a Generic Cap (25 kW for Residential and 100 kW for Non-
Residential)
Residential 25 kW Cap Pros Cons
Administratively Simple Too Large for Smaller Users which
Might Cause Them to Invest in too

Could Limit the Ability to Meet Energy

Demand

Cap
Pros Cons

Might Cause Them to Invest in too

Could Limit the Ability to Meet Energy

Demand Become a Qualifying Facility which
Has a More Challenging

Become a Qualifying Facility which Has
More Accurate Pricing

6.0 Avoided Transmission and Distribution Costs
The Study Scope requested the Company to calculate the value of transmission and distribution
costs that could be avoided by customer-generator exports to the grid.

17 If a qualifying facility elects firm pricing, they receive a higher rate, but are also subject to liquidated damages for
non-performance.

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Study Scope Item 12
Quantify the value of transmission and distribution costs that could be avoided by energy
exported to the grid by net metering customers using the methodology for calculating the
avoided transmission and distribution costs provided by energy efficiency programs.

PacifiCorp’s estimation of the value of energy efficiency measures includes an assumption that
local transmission and distribution upgrades could be pushed into the future.
When the Company provides electric service to a new subdivision it utilizes standard system
designs based on the number and size of expected homes in the new subdivision. It does not
assume any level of customer generation because doing so would risk under-sizing the
equipment.
In the absence of specific information about transmission and distribution capacity needs and
their timing with expected customer exports, PacifiCorp has estimated the potential avoided
transmission and distribution costs using the system LOLP-based capacity value of 3.0%, as
previously discussed. Using the same avoided transmission and distribution upgrade costs
applied in PacifiCorp’s calculation of the energy value and cost-effectiveness of energy
efficiency measures based on the 2021 IRP results in a value of $1.10/MWh over the 2021 IRP
time period.
7.0 Avoided Line Losses
The Study Scope requested the Company the avoided line loss calculations at a level that an
average customer could understand.
Study Scope Item 13
Explain the avoided line loss calculations at a level that an average customer can understand.

As electricity travels from a generator to a customer, some of the energy is lost. This is a
phenomenon known as line losses. One benefit of customer generation is that it is located
closer to the customer and therefore travels a shorter distance which results in lower line
losses.
Line losses are calculated as the difference between the total energy generation that is put into
the grid and the total energy metered at customer sites. The line losses are separated into
three categories: transmission, primary and secondary. Transmission line losses account for
those line losses that occur over the transmission system. Primary line losses include those
losses that occur on distribution voltages in the range from 2.2kV to 34.5 kV with most circuits
at 12.4 kV. Secondary line losses include those losses that occur on distribution systems that
are low voltage in the 120V to 480V range.

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Figure 7.1: Transmission, Primary, and Secondary Components of an Electrical System18
The line losses incorporated in the Company’s current rates are from its 2018 Line Loss Study.
See Appendix 7.1 for the 2018 Line Loss Study. That study identified “Demand” loss factors,
based on losses during peak load conditions, as well as “Energy” loss factors, based on average
losses over the course of a year. The 2018 Line Loss Study identified line losses in Idaho specific
to the following voltage level at which a customer connects to the grid:
Table 7.1: Idaho 2018 Demand and Energy Loss Summary
Voltage Class Demand Loss Factor Energy Loss Factor
Transmission 3.816% 3.503%
Primary 8.121% 7.082%
Secondary 9.834% 9.061%

For customer-generators, the Company expects to apply the export credit to generators
interconnected at secondary voltage levels, and to meter the exports before they go onto the
secondary distribution system. The energy exported from the customer-generators will then
incur some line losses traveling upstream across the secondary distribution system to other
customers, so it will not avoid the entire line losses associated with serving load on the
secondary distribution system. Therefore, the Company recommends crediting exports for
avoiding line losses on the transmission and primary distribution systems only. If customer
exports and customer generation exceeded the load on a particular distribution circuit,
electricity could potential be transferred back up to higher voltages and could incur higher
losses. For distribution capacity, avoided line losses are measured relative to losses at the
transmission demand level, as losses incurred on the transmission system would not have been
transferred across the distribution system.

18 Transmission Line FAQ, GATEWAY WEST Transmission Line Project,
http://www.gatewaywestproject.com/faq_general_transmission.aspx (last visited Feb. 20, 2023).

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8.0 Integration Costs
Integration costs refer to the additional cost of generators with variable output. Integration
typically includes costs related to the uncertainty and variation in variable energy from moment
to moment, and these system impacts have been estimated in the 2021 IRP as described in
more detail below. For customer generation, integration costs could potentially include
equipment and/or operational changes to manage impacts on the distribution system,
particularly at high penetration levels, but the Company has not identified any specific costs
associated with distribution system impacts from customer generators in Idaho.
The Study Scope requested the Company to calculate the dollar impact of delaying a study of
the integration charges for net metering customer until AMI data is available.
Study Scope Item 14
Study other methods for determining the integration costs of net metering customers as a
class. Calculate the dollar impact of deferring a study of the integration charges for net
metering customers until AMI data is available, and if different, calculate the dollar value of
using a zero placeholder until AMI data is available.

The 2021 IRP includes an analysis of wind and solar integration costs in its Flexible Reserve
Study (“FRS”) which is included in this Study as Appendix 8.1: Appendix F – Flexible Reserve
Study- 2021 IRP. That analysis estimates the regulation reserve required to maintain
PacifiCorp’s system reliability and comply with North American Electric Reliability Corporation
("NERC”) reliability standards as well as the incremental cost of this regulation reserve.

PacifiCorp does not have a real-time forecast of customer generation exports that could be
used to identify specific integration requirements, but it is possible to measure changes within
each hour compared to the hourly average. During 2021-2022, the historical customer export
data had a mean average percent error (“MAPE”) of 8.6 percent, when comparing 15-minute
values to the hourly averages. By comparison, the large scale solar in the FRS had a lower MAPE
of 7.2 percent. This indicates that large scale has a proportionately smaller contribution to
regulation reserve requirements than customer exports.
Because the variation in customer generation exports exceeds that of large-scale generation, it
is reasonable to expect integration costs for customer generation exports to be higher. In light
of this, the use of the large-scale solar integration costs likely understates the actual cost but is
reasonable. Using the latest large scale solar integration costs approved in Order No. 34966 in
PAC-E-20-14, the solar integration costs for 2023 is currently $0.24/MWh19. Assuming an

19 See Appendix 8.2: Wind and Solar Integration Charges Approved in Order No. 34966

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average annual exports of 5,000 kWh per customer, the dollar impact of using a zero
placeholder for integration costs until AMI data is available is $1.20 per customer per year.
9.0 Avoided Environmental Costs and Other Benefits
9.1 Grid Stability, Resiliency, and Cybersecurity
The Study Scope requested the Company to quantify the value of grid stability, resiliency, and
cybersecurity provided by on-site generators.
Study Scope Item 15
Quantify the potential value of grid stability, resiliency, and cybersecurity protection provided
by on-site generators as a class and different penetration levels.

The Federal Energy Regulatory Commission (“FERC”) defines resilience as “the ability to
withstand and reduce the magnitude and/or duration of disruptive events, which includes the
capability to anticipate, absorb, adapt to, and /or rapidly recover from such an event”. To
achieve any resiliency or grid stability benefits as defined above, on-site generation must be
combined with storage since on-site generators, on their own, are susceptible to and can even
enhance disruptive events.
Without storage, on-site generation does not provide grid benefits because in the event of an
outage, systems are designed to power down for safety at any penetration level of on-site
generation. The Company has also found that on-site generation does not provide cybersecurity
benefits and can create additional cybersecurity risk because on-site generation creates more
potential access points to the grid.
9.1.1 Grid Benefits of On-Site Generation with Storage
The grid can benefit from on-site generation when it is combined with solar. Battery
management programs, like Wattsmart Batteries, provide four primary grid service benefits: 1)
frequency regulation services 2) peak load management 3) circuit congestion relief, and 4)
backup power.
In 2019, the Company was part of a partnership that developed a 600-unit all-electric
residential community in Utah, where each apartment was outfitted with batteries paired with
rooftop solar. The project provides 12.6 MWh of storage that is dispatchable by RMP through
the Distributed Battery Grid Management System. An evaluation of this project identified the
four primary grid service benefits listed above.
Without battery storage, on-site customer generation does not provide either frequency
regulation services, peak load management, circuit congestion relief or backup power.

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9.1.2 Community Resiliency Benefits of Customer Generation with Storage
When a catastrophic disaster strikes, backup power paired with storage can ensure emergency
services, such as fire, medical, and shelter services, continue to operate. On-site generation
with storage provides value to the community from avoided property damage, injuries,
fatalities, and lost productivity. While there is no standard method for determining the
community resiliency value of customer generation some tools can help determine the value
for individual sites.
An evaluation of Pacific Power’s Community Resiliency Pilot used the Federal Emergency
Management Agency’s (“FEMA”) benefit-cost analysis tool to determine the potential resiliency
value for customer generation and batteries at specific sites that provide vital services—fire
stations, data centers and designated shelters. FEMA’s calculator determines the value of
maintaining these services based on the type of emergency and the facility category. For
example, analysis for a fire station considers the probability of property loss, the dollar value of
the loss, and the number of fire incident prior to and during the outage. The tool also
determines avoided injuries and deaths from maintaining fire service. The resiliency benefits
can vary significantly from site-to-site depending on the unique characteristics of the facility,
the community the facility serves, and the type of disaster.
None of the community resiliency benefits outlined above is possible without battery and
storage combined together since battery storage provides the backup power required during a
disaster. Also, the benefits outlined above are not relevant to the purposes of this Study, which
is focused on the benefits of on-site generators connected to the grid, as a whole, and not any
one site and the benefits it might give to a community in the event of a disaster. Further, those
benefits are unquantifiable and do not accrue specifically to customers of the utility in their
capacity as consumers of energy.
9.1.3 Customer Generation and Cybersecurity Protection
Cyber-attacks are potential resiliency events. Thus, the cybersecurity protection benefits of
customer generation with storage are the same as those described above. In the event of a
catastrophic cyberattack, customer generation and storage could provide sustained power to
vital services.
However, increasing penetration of customer generation could increase cybersecurity risks. The
U.S. DOE’s report on “Cybersecurity Consideration for Distributed Energy Resources on the U.S.
Electric Grid” identifies several cybersecurity risks from distributed energy resources.20 When a

20 Cybersecurity Considerations for Distributed Energy Resources on the U.S. Electric Grid, U.S. DOE Office of
Cybersecurity, Energy Security, and Emergency Response and the Office of Energy Efficiency and Renewable
Energy, October 2022. https://www.energy.gov/sites/default/files/2022-
10/Cybersecurity%20Considerations%20for%20Distributed%20Energy%20Resources%20on%20the%20U.S.%20Ele
ctric%20Grid.pdf

32 | P a g e

customer-generator connects to the grid, it creates a new access point, which adds incremental
risk for cyberattacks. Most customer generation systems use solid-state inverters to produce
output and sync with the grid. These inverters are software-driven and digitally controlled. The
improper application of this software—such as through a cyberattack—could affect reliability
and grid stability.
9.2 Public Health and Safety
The Study Scope requested the Company to quantify the value to local public health and safety
from reduced local impacts of global warming.
Study Scope Item 16
Quantify the value to local public health and safety from reduced local impacts of global
warming such as reduced extreme temperatures, reduced snowpack variation, reduced
wildfire risk, and other impacts that can have direct impacts on Rocky Mountain Power
customers.

The value of customer generation exports with respect to global warming harm reduction is
difficult to quantify. The greenhouse gas costs in the 2021 IRP represent possible federal policy
that would impact the dispatch of emitting resources, and do not represent local impacts,
which are much more complex. Some of the referenced global warming impacts, including
impacts on retail load and hydropower production, directly impact PacifiCorp’s loads and
resources, and climate-related effects on these inputs have been incorporated in PacifiCorp’s
2023 IRP.
Though it is imperfect for identifying local impacts, PacifiCorp’s avoided energy value,
addressed in section 4.3 of this Study, includes the impact of assumed medium greenhouse gas
costs, consistent with assumptions from the 2021 IRP. Medium greenhouse gas costs are
reflected in market prices, as well as in the dispatch cost of PacifiCorp’s coal and natural gas-
fired resources, but it is not possible to differentiate greenhouse gas costs from energy and
other variable costs within the reported hourly energy value. PacifiCorp’s 2021 IRP also
included analysis using a social cost of greenhouse gases (“SCGHG”); however, this represents
global public health and safety impacts, rather than local impacts.
Another possible value of customer generation exports is via Renewable Energy Certificates
(“RECs”), which are addressed in section 9.4 of this Study below.
9.3 Economic Benefits
The Study Scope requested the Company to quantify the value to local economic benefits from
on-site customer generation.

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Study Scope Item 17
Quantify local economic benefits, including local job creation and increased economic activity
in the immediate service territory.

Quantifying local economic benefits of increased economic activity is difficult, if not impossible,
to quantify with a degree of certainty. In addition, the Company’s generation, transmission, and
distribution activities in its current service territories provide economic benefits. However, the
Company does not charge customers for these benefits in electric rates. Allowing difficult-to-
quantify economic benefits in the ECR would not be fair to non-participating customers.
9.4 Possible Net Value of Renewable Energy Credits
The Study Scope requested the Company to quantify the net value of RECs sales from on-site
generation.
Study Scope Item 18
Quantify the possible net value of Renewable Energy Credit sales produced by net metering
exported energy.

Currently, Idaho does not have a renewable portfolio standard (“RPS”), so the benefits of RECs
would come from REC sales. Only renewable generation delivered to the electric grid can
qualify for RECs, and there are administrative requirements to certify renewable resources and
assign RECs to their production.
To create RECs, the renewable energy generator must be registered with the Western
Electricity Coordinating Council (“WECC”) and the Western Renewable Energy Generating
Information System (“WREGIS”). Renewable energy cannot be monetized through REC sales
without this process in the WECC region. Coordinating the certification and tracking of the RECs
would be complex and could require a full-time employee to administer. The Company expects
the administrative costs would exceed any revenues generated from REC sales.
At present, PacifiCorp does not sell all the RECs it generates on behalf of its Idaho retail
customers, as the market for RECs is limited. To the extent that there were other parties
interested in purchasing RECs from Idaho customer-generator exports, a $1/MWh REC price
would equate to approximately $5 per year in incremental export credit value for an Idaho
customer-generator, assuming 5,000 kWh of exports annually, which represents approximately
half of their annual generation.
9.5 Reduced Risk from End-of-Life Disposal
The Study Scope requested the Company to quantify the reduced risk from end-of-life disposal
concerns for the Company compared to fossil-fueled resources.

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Study Scope Item 19
Quantify the reduced risk from end-of-life disposal concerns for the Company compared to
fossil-fueled resources.

Investment in utility scale resources considers end-of-life closure costs to determine least cost
resources. To the extent capacity benefits displace a new generation resource, this potential
benefit is already captured in that category.
10.0 Recovering Export Credit Rates in the ECAM
10.1 Current Export Credit Recovery
To better understand how export credit rates may be recovered in the Energy Cost Adjustment
Mechanism (“ECAM”), the Study Scope asked the Company to explain the method currently
used to record net metering bill credit costs.
Study Scope Item 20
Explain the method currently used to record net metering bill credit costs.

Currently, bill credits for net metering are used to reduce the energy charges that are paid to
the Company. These net metering bill credits therefore reduce the Company’s retail revenue.
10.2 Recovery Allocation
The Study Scope asked the Company to quantify the current amount of net metering costs
allocated to each class.
Study Scope Item 21
Quantify the current annual amount of the net metering costs allocated to each class.

Table 10.1 below shows the reduction in revenue for each class attributable to exported energy
that is valued at retail energy charges:
Table 10.1: Net Metering Reduction in Revenue by Class
Sch 1 Sch 36 Sch 23 Service Sch 6
(MWh)

8,555 2,183 565 123 11,426
Value at Retail Rate

The Study Scope required the Company to explain how these costs have been allocated and
recovered between rate classes for the past five years.

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Study Scope Item 22
Present and explain how these costs have been allocated and recovered between rate classes
for the past five years.

In between rate cases, the Company absorbs the cost of reduced revenue from net metering. In
2021, the Company filed a rate case that updated class revenues and that took effect January 1,
2022. The rate case before the 2021 rate case occurred ten years before and took effect on
January 10, 2012, with a second-year price change that took effect on January 1, 2013. During
that timeframe, onsite generation adoption was still in its infancy and was a small portion of
retail revenue situs directly assigned to each customer class. Exported energy from on-site
customer-generators reduces net power cost (“NPC”) by reducing purchases or fuel costs.
While these cost savings reduce NPC which is captured in the ECAM, the cost of paying for
exported energy that is above what is built into the revenue for a general rate case is absorbed
by the Company. The cost of the ECAM is allocated to customer classes on the basis of energy
sales adjusted for line losses.
10.3 Export Credit Price Scenarios
The Study Scope asked the Company to quantify the annual export costs for each customer
class and different assumed export rates.
Study Scope Item 23
Quantify these annual costs under the assumptions that the Export Credit Rate is the retail
rate, 7.4 cents/kWh, 5 cents/kWh, or 2.23 cents/kWh.

Assuming instantaneous netting, the export credit payments by class are show in Table 10.2 for
the different specified export credit prices.
Table 10.2: Annual Export Costs by Rate
Residential
Sch 1 Sch 36 Service Sch 23 Service Sch 6
8,555 2,183 565 123 11,426
$916,330 $269,067 $51,091 $5,242 $1,241,731
$633,050 $161,516 $41,835 $9,126 $845,526
$427,736 $109,132 $28,267 $6,166 $571,301
$190,770 $48,673 $12,607 $2,750 $254,800

The Study Scope called for an analysis how these costs would be allocated and recovered by
each rate class through the Company’s ECAM.

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Study Scope Item 24
Analyze how these costs would be allocated and recovered by rate class through the
Company’s proposed ECAM method going forward.

Going forward, the Company recommends that the export credits paid to customer generators
on the net billing program would be recorded as a purchased power expense and tracked in the
ECAM like all other energy purchases. This would match the cost exported energy with any
reductions to net power costs by avoided purchases or reduced fuel expense. The Company
recommends that the cost of export credits would be allocated to customer classes on energy
sales adjusted for line losses, which is consistent with how other ECAM costs are treated.
11.0 Schedule 136 Implementation Issues
The Study Scope asks the Company to consider several implementation issues such as billing
structure for on-site generators, export credit expiration scenarios, and the frequency of export
credit updates.
11.1 Billing Structure
11.1.1 Time-of Delivery Pricing
The Study Scope requested an explanation of how seasonal and time-of-delivery price
differences will be used to help match up customer generated exported energy with the
Company’s needs and how using more granular time periods for energy and capacity credits
could be used to match up customer-generated exports more closely with the Company’s
system needs.
Study Scope Item 25
Explain if and how seasonal and time-of-delivery price differences will be used to help align
customer generated exported energy with the Company’s system needs.

Study Scope Item 26
Explain if and how using more granular time periods for differentiating energy and capacity
credits could be used to more closely align customer-generated exports with the Company’s
system needs.

There are both pros and cons to setting the price for export credits based upon season and time
of use period instead of using a flat, year-round export credit price that is the same in all hours.
Using prices that vary by period, seasonal and time of use, provides a more accurate price signal
that may help customers optimize both their generation design and their usage habits. For
example, a higher on-peak export rate may encourage a customer to deploy west facing solar
panels that produce more during high value evening periods, or a customer might make a

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stronger effort to use energy during lower cost middle of the days times. However, the
difference between retail rates for energy taken from the grid as compared to a flat export
price may provide sufficient incentive to do this anyways. All the Company’s Idaho customers
are subject to electricity prices that vary based upon season, but most customers are not on a
time of use option. Making prices more granular may be confusing to customers and may make
the decision whether to build onsite generation or not a more difficult decision to make. Table
11.1 below lists the pros and cons of seasonal and time of use export credit pricing as compared
to flat export credit pricing:
Table 11.1: Pros and Cons of Seasonal and Time of Use Export Credit Pricing
Prices
More Accurate Pricing More Confusing for Customers
Consistent with Seasonality for the
Price at which Customers Buy
Energy from the Grid
Adopting Onsite Generation
Time of Use Export Prices

Pros Cons
Deployment of Generation and
Energy Usage Habits
Adopting Onsite Generation
Most Customers are Not Subject to Time of Use
Pricing

Table 11.2 below shows what the export credit price in 2025 would look like based upon the
export credit values on Table 4.1 if it were flat, seasonal, time of use, or seasonal and time of
use. Note that each of the four time of use period definitions shown result in the same
compensation for a customer whose exports align with the average export profile. Customers
who are able to export more during on-peak and/or summer periods would receive higher
compensation with differentiated rates.

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Table 11.2: Illustrative Export Credit Prices Under Different Modes of Time Granularity

h
Jun-
Oct
¢/kWh
Nov-
May
¢/kWh
On-
Peak
¢/kW
h
Off-
Peak
¢/kWh
Jun-
Oct
On-
Peak

Oct
Off-
Peak

May
On-
Peak

May
Off-
Peak

2.30
3.22 1.62
4.89 1.93
Time of Use
5.26 2.57 2.99 1.57

Whether the credit is set using a seasonal, time of use, or a hybrid approach, it is recommended
that the ECR would be the same for all customer classes with on-site generation including
residential, general service, and irrigation customers. Keeping the same ECR for all classes
would minimize complexity and potential customer confusion.
11.1.2 Economic Evaluation for Customer-Generators and On-Site Generation System
Installers
The Study Scope requested an explanation of how potential customer generators and on-site
generation system installers can have accurate and adequate data and information to make
informed choices about the economics of on-site generation systems over the expected life of
the system.
Study Scope Item 27
Explain how potential customer-generators and on-site generation system installers will have
accurate and adequate data and information to make informed choices about the economics
of on-site generation systems over the expected life of the system.

The purpose of customer generation programs like net metering or net billing is to offset part
or all the Customer’s own electrical requirements and not to enable customers to become an
independent power producer. If the customer’s intent is to offset its own usage, then customer
generators and system installers have the same customer usage information and pricing to
make informed choices about the economics of on-site generation systems as they do to make
decisions about other energy investments like conservation focused measures such as more
efficient windows or air conditioning equipment. Under net billing, customer-generators would
be encouraged to match up their usage with generation. This can be done behaviorally through
actions such as running appliances like dishwashers during the middle of the day, sizing their
systems at levels that reduce exports, or installing onsite storage. A customer can ask the
company that is selling the renewable generation equipment for an estimate of hourly
expected energy output. An estimate of hourly solar production can also be obtained from the

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National Renewable Energy Laboratory’s PVWatts tool21. With the installation of AMI,
customers are able to view their hourly usage online which should allow determined customers
to analyze their usage patterns.
11.1.3 Residential Solar Energy Disclosure Act
The Study Scope requested an explanation of how on-site generation system installers will be
able to comply with the Residential Solar Energy Disclosure Act if hourly or instantaneous
netting and/or granular time-differentiated export rates are adopted and updated annually.
Study Scope Item 28
Explain how on-site generation system installers will be able to comply with the Residential
Solar Energy Disclosure Act if hourly or instantaneous netting and/or granular time-
differentiated export rates are adopted and updated annually.

As explained in response to Study Scope item 27, the intent of net metering or net billing is not
for customers to become developers of qualifying renewable generation resources or to get
into the business of selling energy to the Company. The purpose is to offset the customer’s own
usage. Inasmuch, as net billing customers use the generation they produce onsite, they will
avoid paying the retail price for energy. When customer generators send export energy to the
utility grid, they will be compensated at the export credit price which would update
periodically. The value of exported energy could change over time. Before committing to install
onsite generation, customer generators should take note that all investments including rooftop
solar have risks. While under net billing, a customer generator will save on their utility bill from
producing energy, those savings may go up or down with time. In many ways installing onsite
generation is like choosing to purchase a hybrid or electric vehicle. An individual who makes
this choice would save on gasoline over time, but those savings levels fluctuate with the
changing price of gasoline. Under the Residential Solar Energy Disclosure Act, installers will
need to document for their potential customers the assumptions used in their projection of
savings for the system.
11.2 Export Credit Expiration
To evaluate different scenarios for export credit expiration, the Study first evaluated the
current magnitude of accumulated export credits and generation. Then, the effects of different
expiration periods were analyzed to see how customers would be affected. Finally, the Study
looked at how the Company and non-participating customers are impacted by expired credits.
11.2.1 Accumulated Export Credits
The Study Scope requested the magnitude, duration, and value of accumulated export credits
as of August 1, 2020, be quantified.

21 See https://pvwatts.nrel.gov/

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Study Scope Item 29
Quantify the magnitude, duration, and value of accumulated export credits as of August 1,
2020.

As of August 1, 2020, there was a total of 4,530,405 kWh in excess generation for all customers
as detailed in Table 11.3 below
Table 11.3: Excess kWh Total as of 8/1/2020
Class
Residential
21,729 46,758 59,349 140,598 215,748 631,720 1,141,045 1,226,213 3,483,160
Small
Commercial

41,462 70,153 61,235 92,809 158,167 245,993 195,306 163,280 1,028,405
Large
Commercial

- 80 240 440 320 1,040 2,560 14,160 18,840
Irrigation
- - - - - - - - -
Total
63,191 116,991 120,824 233,847 374,235 878,753 1,338,911 1,403,653 4,530,405

To better understand the magnitude, duration, and value of the excess generation, the
Company valued each year’s excess generation by customer class and rate. In addition to the
table above, the Company evaluated expired generation from August 1, 2020, to December 31,
2022, to provide a more current view of expired credits. This detail is provided on the summary
tab of Appendix 11.2: Idaho Expired Credit Analysis 2012-2022. The estimated value of all
excess generation is $325,386.06 for all 2,196 net metering customers from 2012 to 2022.
11.2.2 Impact to Customers over Various Expiration Periods
The Study Scope requested the impact to customers of a 2-year, 5-year, and 10-year expiration
periods be quantified.
Study Scope Item 30
Quantify the impact to customers of a 2-year, 5-year, and 10-year expiration periods.

The impact to customers for credits expiring at either 2-years, 5-years, and 10-years, will vary
depending on each customer’s load and system size. Customers with systems that consistently

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overproduce, will be most affected by expiring credits. As shown on the Table 11.2 below, 14
percent of on-site generation systems overproduced in 2022.22
Table 11.4: Percentage of Customers Overproducing Annually
2 8 10 21 29 59 122 212 215 281
Commercial
4 4 4 5 5 9 12 19 23 16
Commercial
- - - - - - - 1 - -
- - - - - - - - - 2
5% 9% 9% 12% 10% 10% 12% 16% 14% 14%

The average annual compensation for net overproducers has been $294 over the last 5 years.23
A breakdown of the weighted average for each customer class for the last 5 years is included in
Table 11.5 below. The net value of overproduction for each of the overproducers is provided in
detail in Appendix 11.1: Weighted Average Overproduction.

22 Additional analysis included on the customer count tab of Appendix 11.2: Idaho Expired Credit Analysis 2012-
2022.
23 See summary tab of Appendix 11.1: Weighted Average Overproduction.

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Table 11.5: Weighted Average of Customer Overproduction
Year Ending 2018 2019 2020 2021 2022
Residential Count
Average Annual
Compensation/Customer
$276.02 $209.22 $196.26 $207.12 $200.37
9 12 19 23 16
Compensation/Customer
$1,937.71 $875.56 $785.77 $499.72 $615.28
- - 1 - -
Compensation/Customer
- - $842.27 - -
- - - - 2
Compensation/Customer
- - - - $54.08
68 134 232 238 299
Compensation/Customer
$495.95 $268.89 $247.33 $235.40 $221.60

To better understand how the overproducing customers would be impacted by different
expiration periods, the Company took a sample of the overproducing customers and calculated
the value of credits that could be subject to expiration over the different time periods. The
results of this analysis can be seen on Appendix 11.3: Customer Impact at 2-, 5-, and 10-Year
Expiration.
As shown on the residential tab of Appendix 11.3, only two customers overproduced for the
year in 2013. At the end of the 10-year period, those two customers would have $1,177.5 in
combined credits that would begin to expire, on a rolling basis.
For the 5-year analysis, the two customers from the 10-year analysis were analyzed again along
with the largest overproducer in 2018. The overproducing site was selected to show how
customers with both large and small amounts of overproduction would be affected by expired
credits. As shown on the residential tab of Appendix 11.3, two of the customers would not have
any expired credits when looking at the last five years, however the largest overproducer would
have $9,927.32 in credits that would begin to expire on a rolling basis of approximately $2
thousand annually. While the impact to this customer could potentially be significant, most
customers would not be heavily impacted by the expiration of credits over a 5-year period.
For the 2-year analysis, the customers from the 5-year analysis were included and added a
customer that was at the median range for overproducers to analyze the impact to the

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broadest possible range of overproducers. The average annual credit of the four selected
customers was $82 that would expire on a rolling basis.
In summary, over 85 percent customers will not be affected by expiring credits. For those
overproducers with credits at risk of expiration, the impact will vary depending on system size
and load. The most over-sized customer could see credits valued at approximately $2 thousand
expiring annually. In contrast, the average overproducer would not have more than $100 in
credits expire on an annual average basis.
11.2.3 Export Credit Expiration Policy
The Study Scope requested an explanation of the need for credits to expire.
Study Scope Item 31
Explain the need for credits to expire.
a. Show how the Company does or does not benefit from the expiration of customer
export credits.
b. Show how non net bill customers are harmed or benefited from the expiration of
customers export credits.

Customer generation programs are intended for customers to offset some or all of their energy
bill with onsite generation and not for a customer to become a power producer. The intention
of credit expiration is to encourage customers to size their generation systems to match actual
usage at the site of the system.
When establishing net metering the Commission confirmed that: “The purpose of net metering
is not to encourage excess generation. Developers of qualifying renewable generation
resources who wish to get into the business of selling energy to the Company should, under
PURPA, request firm or non-firm energy purchase contracts.”24 The net metering rate is not
intended to encourage participants to become independent power producers. If the ECR is not
set at a level that holds other customers economically indifferent from paying for the exports or
another comparable source of energy, other customers are harmed by having to pay an
unreasonable rate.
11.2.4 Treatment of Financial Credits
There are different ways financial credits generated from excess exported energy can be
treated considering how they can be payable to the customer, transferrable to other meters,
and how they can be applied to different charges. Presently, customer generators may use
their excess credits to offset any/all charges. Excess credits are paid out to the customer
generator when they discontinue service with the Company. Excess credits may only be
transferred to same customer’s other metered sites if the meter is located on or contiguous to

24 In the Matter of the Petition of NW Energy Coalition and Renewable Northwest Project to Establish Net Metering
Schedules for PacifiCorp. Case No. PAC-E-03-4, Order No. 29260 at p. 6.

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the premises, served by the same primary voltage circuit, and on the same rate schedule as the
meter where the excess credits were generated. A $10 administrative per meter fee is charged
for transferring those credits.
There are pros and cons to different treatments of excess exported credits. The advantages of
allowing the credits to be payable to a customer generator when they discontinue service are
that it is seen as fairer to the customer, and potentially creates less customer complaints. The
disadvantages of paying out credits when service is discontinued are that it increases the cost
to non-participating customers, it can increase administrative burden for the utility, and it may
encourage a customer to oversize its generation system instead of sizing its system to meet its
own usage needs. There are similar advantages and disadvantages for allowing credits to be
transferrable to different accounts and for allowing the credits to apply to all charges instead of
only being able to apply them against energy charges. Table 11.5 lists the pros and cons of
excess credits being payable at account closing, transferrable to other meters, and able to
offset any charge.
Table 11.6: Pros and Cons of Different Treatments for Financial Credits from Excess Exported
Energy
Account Closing
Fairness to customers who
generated the credits with issuing checks when the account

customers to oversize their systems

for non-participants
Credits Transferrable to
Other Accounts
Customer satisfaction for
customers with multiple
meters on their account
credits

their systems
Credits Applicable to All
Charges
Less customer complaints May encourage customers to oversize
their systems

11.2.5 Treatment of Existing Credits for Non-Legacy Customer Generators
Currently, credits for excess exported energy for non-legacy (Schedule 136) customer
generators are valued at the full retail value of energy charges and held on the customer’s
account as a financial (not a kWh) credit. These credits never expire and are paid out when the

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customer closes its account. This treatment ensures fairness for the customer generator. A
further change could be made to allow those credits to be transferrable to any account. This
would give non-legacy customer generators even more flexibility to make use of their excess
export credits.
11.3 Export Credit Updates
An export credit can be updated at different frequencies such as every year or every other year.
Updating more frequently can make the price more accurate since it uses more current
information. Updating more frequently can also require more administrative burden for the
utility and for the Commission and stakeholders who review the filing.
One option is to update some parts of the price more frequently and other parts of the price
less frequently. The Company does this for its export credit price in Utah. While the export
credit price in Utah is updated every year, only the energy value and the hourly export shape
change every year. Other components such the integration cost or capacity value change only
with new IRPs. Changes to the methodology can be changed, but take a longer review process.
11.3.1 SAR Energy Rates Updates and IRP Cycle Impact to Export Credit Updates
The Study Scope requested the impact of biennial updates, as compared to annual updates of
the ECR, by comparing the changes in the SAR energy rate, line losses, and integration costs
using historical data over one year, one IRP cycle and two IRP cycles be quantified.
Study Scope Item 32
Quantify the impact of biennial updates as compared to annual updates of the Export Credit
Rate by comparing the changes in the SAR energy rate, line losses, and integration costs using
historical data over one year, one IRP cycle (two years), and two IRP cycles (four years).

Assuming the ECR is updated based upon non-levelized annual prices, the Company analyzed
how compensation would vary for a customer generator who exports 5,000 kWh per year
under different update scenarios – annual, biennial, and every 4 years. The chart below in
figure 11.1 shows how the price would have varied under these cycles starting with the prices
effective around June 1, 2012, for a ten-year period:

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Figure 11.1: Frequency of Export Credit Updates25

Table 11.7 shows how compensation for an annual 5 MWh of exports over this ten-year period
would have compared for the different update cycle scenarios:
Table 11.7: Impact of Different Update Cycles
Price Price Price
$1,735 $1,446

The results for the annual update and the biennial update are nearly identical. The 4-year
update is lower primarily, because it misses capturing higher prices that occurred in 2014 and
2015 that get picked up in annual and biennial updates. Depending upon when updates begin
could make a large difference for multi-year updates in the future. Updating the ECR annually
would provide customer generators with more accurate compensation.
For Rocky Mountain Power, there would be benefits to matching up the timing of export credit
price updates in Idaho with Utah. In Utah, Rocky Mountain Power makes a filing with the Utah
Public Service Commission on or around the end of January each year for export credit prices
that go into effect on March 1.
12.0 Smart Inverter Study
The Study Scope requested an explanation of the Company’s Utah smart inverter policy and a
quantification of the benefits of applying that policy to its Idaho service territory.
Study Scope Item 33
Explain the key aspects of the Company’s Utah smart inverter policy and quantify the benefits

25 See Appendix 11.4: SAR Export Credit Analysis for calculation
20
25
30
35
40
45
50
55
60
$/
M
W
h
Annual Update Price Biennial Update Price 4-Year Update Price

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of applying that policy in its Idaho service territory, in particular, the potential benefits of
reactive power control.

In 2017, Rocky Mountain Power took part in a Smart Inverter Project as part of the Utah
Sustainable Transportation and Energy Plan (“STEP”) to investigate the capabilities and impacts
of smart inverters on the Company's distribution system. The Company's project partners
included the Electric Power Research Institute and Utah State University and resulted in the
study of: (1) IEEE 1547 smart inverter standards and policy, (2) laboratory selection and testing,
(3) hosting capacity results, with and without smart inverters, (4) settings determination, (5)
deployment best practices, and (6) Technical Policy 138, interconnection standard updates. The
Smart Inverter Study was produced from the efforts of the STEP project in Utah docket 19-035-
17 and is included with this Study as Appendix 12.0: Utah STEP - Smart Inverter Study.
This research produced the smart inverter policy that the Company has implemented for its
Utah customers. That policy was considered in a Utah Public Service Commission proceeding to
determine how the value provided by customer smart inverters should be included in the ECR,
Utah Docket No. 17-035-61, and no specific export credit value was applied to account for the
benefits of smart inverter technology.
While smart inverters are not expected to impact export credit rates, including minimum
requirements for inverter technology can ensure the hosting capacity and power quality of the
distribution system do not get worse as customer generation is added.
The following Appendices are voluminous and provided in their na�ve format via Box:

Appendix 3.1: Customer Generator Export and Genera�on Informa�on
Appendix 4.1: Export Profile Jan21-Dec22
Appendix 4.2: Export Credit Calcula�on
Appendix 4.3: Customer Genera�on Exports During Peak Loads
Appendix 4.4: Idaho Export Profile Valida�on Avg Capacity
Appendix 4.5: ID Export Profile Valida�on Monthly Exports
Appendix 4.6: ID Export Profile Valida�on PV Wats Produc�on
Appendix 4.7: Appendix K - Capacity Contribu�on - 2021 IRP
Appendix 7.1: PacifiCorp-Idaho 2018 Electric System Loss Study
Appendix 8.1: Appendix F - Flexible Reserve Study- 2021 IRP
Appendix 8.2: Wind and Solar Integra�on Charges Approved in Order No. 34966
Appendix 11.1: Weighted Average Overproduc�on
Appendix 11.2: Idaho Expired Credit Analysis 2012-2022
Appendix 11.3: Customer Impact at 2-, 5-, and 10-Year Expira�on
Appendix 11.4: SAR Export Credit Analysis
Appendix 12.0: Utah STEP - Smart Inverter Study

Page 1 of 1
CERTIFICATE OF SERVICE
I hereby certify that on this 8th of February, 2024, I caused to be served, via electronic mail a true and correct copy of Rocky Mountain Power’s On-site Generation Study Supplement to the service list in Case No. PAC-E-23-17 to the following: Service List
Eric L. Olsen
ECHO HAWK & OLSEN, PLLC
505 Pershing Ave., Ste. 100 P.O. Box 6119 Pocatello, Idaho 83205 [e-mail]

2623 NW Bluebell Place
Corvallis, OR 97330 E-mail: [e-mail]
Claire Sharp Deputy Attorney General Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg No. 8,
Suite 201-A (83714) PO Box 83720 Boise, ID 83720-0074 [e-mail]
Rocky Mountain Power
Rocky Mountain Power 1407 West North Temple, Suite 320 Salt Lake City, Utah 84116 [e-mail]
PacifiCorp 825 NE Multnomah, Suite 2000
Portland, OR 97232
[e-mail]
Rocky Mountain Power 825 NE Multnomah, Suite 2000 Portland, OR 97232 [e-mail]
Dated this 8th day of February, 2024.
__________________________________ Santiago Gutierrez
Coordinator, Regulatory Operations