20200826Final_Order_No_34753.pdf

ORDER NO. 34753 1

Office of the Secretary
Service Date
August 26, 2020

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

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
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CASE NO. PAC-E-19-08

ORDER NO. 34753

On June 14, 2019, Rocky Mountain Power, a division of PacifiCorp (“Rocky Mountain
Power” or “Company”) applied to the Commission for an order closing Electric Service Schedule
135 – Net Metering Service (“Schedule 135” or “Net Metering Service”) to new customers after
December 31, 2019, and opening Electric Service Schedule 136 – Net Billing Service (“Schedule
136” or “Net Billing Service”) to new customers as of February 1, 2020 (“Original Application”).
On July 18, 2019, the Commission issued a Notice of Application and Notice of
Intervention Deadline. Order No. 34379.
On December 20, 2019, the Commission issued a final order in IPC-E-18-15 rejecting
a proposed Settlement Agreement for Idaho Power’s net metering program. Order No. 34509. On
February 5, 2020, the Commission issued a final order on reconsideration in IPC-E-18-15
upholding its decision to reject the proposed Settlement Agreement. Order No. 34546.
On March 10, 2020, the parties met to discuss how to proceed with Rocky Mountain
Power’s Application given the Commission’s directives in Order Nos. 34509 and 34546 issued in
IPC-E-18-15.
On April 23, 2020, Rocky Mountain Power submitted a supplemental application
(“Supplemental Application”). The Supplemental Application proposed closing Schedule 135 to
new customer’s as of July 31, 2020, and opening Schedule 136 as of September 1, 2020. The
Supplemental Application also updated inputs to the Company’s proposed export credit rate
(“Export Credit Rate”).
On May 6, 2020, the Commission issued a Notice of Supplemental Application, Notice
of Public Hearing, and Notice of Comment Deadlines. Order No. 34661. The Commission set a
procedural schedule designed to allow the parties to integrate customer feedback into their
respective comments. The Commission set a deadline of May 26, 2020 for initial comments, July

ORDER NO. 34753 2
3, 2020 for revised comments, and a deadline of July 16, 2020 for party reply comments and public
comments on the study design phase. The Company hosted a telephonic public workshop on June
16, 2020. Commission Staff hosted a live-streamed public workshop on June 18, 2020. The
Commission held a telephonic public hearing on June 22, 2020.
On July 31, 2020, the Commission suspended the Company’s proposed effective date.
Order No. 34745.
Idaho Irrigation Pumpers Association, Inc., Idaho Conservation League (“ICL”), Idaho
Clean Energy Association, Inc. (“ICEA”), and Monsanto Company intervened as parties.
Now, the Commission issues an order defining the scope of the study to be conducted
by the Company. Concurrently and separately, the Commission issues Order No. 34752, a
proposed order on grandfathering existing customer-generators pursuant to Commission Rule of
Procedure 312.
BACKGROUND
The Company’s Net Metering Service was first approved by the Commission in 2003
in response to a petition from the NW Energy Coalition and Renewable Northwest Project. Order
No. 29260. Schedule 135 was modeled on Idaho Power’s Schedule 84. Id. at 6. Schedule 135
allows for monthly netting of energy production and consumption. Under Schedule 135, net
monthly generation is compensated by an export credit at the customer’s retail rate, which can be
carried forward indefinitely, transferred among meters in the customer’s name on contiguous
property, and applied to the customer’s bills for net consumption of electricity. In approving the
Company’s proposed tariff, the Commission stated, “This opportunity to run the meter backwards
and offset usage is the primary purpose of net metering.” Id. The Commission said, “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 [the Public Utility Regulatory Policies Act of 1978] request firm or non-firm energy
purchase contracts.” Id. at 6-7.
In 2016, the Company petitioned the Commission to raise the cap on overall customer
participation from 714 kW to 2,000 kW. The Commission agreed to remove the 714 kW cap but
declined to impose the 2,000 kW cap, finding “the cap did not serve its intended purpose, the
Company has not expressed any immediate reliability concerns, the subsidization level is currently
small but growing, and the Company plans to propose modifying the net metering service and rate

ORDER NO. 34753 3
design to address subsidization as part of its next general rate case. Order No. 33511 at 7. The
Commission directed the Company to file a report annually. The Commission stated the report
“should discuss, without limitation, customer participation levels, generator types, nameplate
capacity, total generation, contribution to system peak, impacts on non-net metering customers,
potential impacts to power quality and reliability, etc.” Id. These reports are available on the
Commission website in the PAC-E-16-07 case file.
This case was originally filed on June 14, 2019 while the Commission was processing
two net metering cases for Idaho Power, IPC-E-18-15 and IPC-E-19-15. When the Commission
denied the proposed Settlement Agreement in IPC-E-18-15, the Commission prescribed a
procedure and criteria to ensure an open and robust review of future Idaho Power net metering
proposals. The Commission identified the need for a credible and fair study to form the basis of
proposed changes to net metering service offerings and identified three criteria for a credible and
fair study. 1) The study must use the most current data possible and the data must be readily
available to the public and in the Commission’s decision-making record. 2) The study must be
designed in coordination with the parties and the public, including opportunities for public
participation in the study design and the study review phase with the final scope of the study to be
determined by the Commission. 3) The study must be written to be understandable to the average
customer but withstand expert scrutiny. Order No. 34509 at 9. The parties to this case proposed
a schedule based on the directives in the IPC-E-18-15 orders. See Supplemental Application at ¶
14. This order completes the “study design” phase and determines the scope of the study the
Company is to undertake.
SUPPLEMENTAL APPLICATION
The requests for relief in the Company’s Supplemental Application can be summarized
as requests for the Commission to: 1) close Schedule 135 to new participants and grandfather
existing customer-generators on Schedule 135 for ten years; 2) open Schedule 136 to new
customer-generators; 3) impose an $85 application fee for Schedule 136 applicants; and 4) allow
the Company to recover export energy credits through the Company’s Energy Cost Adjustment
Mechanism (“ECAM”). In Order No. 34752, the Commission’s proposed order addresses all but
the ECAM request.
In its Original Application, and supporting testimony, the Company proposed
immediate implementation of an Export Credit Rate upon the Commission opening Schedule 136.

ORDER NO. 34753 4
Original Application at ¶ 12, MacNeil, Di. At 1-2. In its Supplemental Application, the Company
requests the Commission establish Schedule 136 on the same terms as Schedule 135 but with an
Export Credit Rate initially set at the customer’s retail energy rate until the Commission approves
and implements an Export Credit Rate. Supplemental Application at ¶ 22.
The proposed method for calculating the Export Credit Rate is the same in the Original
Application and the Supplemental Application, although the Supplemental Application uses
updated inputs. In the Original Application, the Export Credit Rate was calculated to be $24.86
per MWh. MacNeil, Di at 2. In the Supplemental Application, the Export Credit Rate was
calculated to be $22.34 per MWh. Supplemental Application at ¶ 16. The Company proposes
these values “be differentiated by on-peak / off-peak and summer / winter periods that reflect
higher and lower avoided cost values . . .” MacNeil, Di at 13.
The Company proposes to calculate the avoided energy component by using a time-
differentiated variation of the Commission’s Surrogate Avoided Resource methodology (“SAR
Method”). The Commission uses the SAR Method to calculate published avoided cost rates for
qualifying facilities under the Public Utility Regulatory Policies Act of 1978. The SAR Method
is based on the fixed costs and operations and maintenance costs required to build and operate a
hypothetical Combined Cycle Combustion Turbine (“CCCT”) natural gas power plant. The SAR
Method uses natural gas forecasts and an assumed heat rate for CCCTs to calculate what the
operation costs would be for the hypothetical plant.
The Company proposes to modify the SAR Method to account for the different value
of energy provided by customer-generators at different times of day and in different seasons of the
year, and to reflect the Company’s description of the resource as “non-firm.” The Company states
non-firm pricing is appropriate for on-site generation customers because, “Firm contracts would
include credit terms, security deposits, performance guarantees, liquidated damages, default
provisions, and termination rights that are not found in the Schedule 136 tariff.” MacNeil, Di-3-
4. Therefore, the Company proposes a 15% reduction to the Export Credit Rate to reflect the non-
firm nature of the resource. Id. at 3.
Under the Company’s proposal to calculate the hourly Export Credit Rate, the
Company assigns a value to each hour of the day based on that hour’s historic relation to average
market price, as measured by the Company’s PacifiCorp east (“PACE”) Energy Imbalance Market
(“EIM”) for the most recent 12-month period. Id. at 4. The Company uses the example, “For

ORDER NO. 34753 5
instance, if the average market price during hour-ending 10 in May is $18/MWh, and the average
market price during all hours in May is $20/MWh, then the scalar for hour-ending 10 in May would
be 90 percent.” Id.
The Company further adjusts this value by applying on-peak and off-peak pricing. The
Company proposes to define on-peak pricing as 4:00 p.m. to 10:00 p.m. Mountain Time, Monday
through Friday excluding holidays. Id. at 9. The Company proposes the Export Credit Rate be
52% higher for exports during on-peak hours than off-peak hours. Id. at 10. The Company also
differentiates energy values based on season, assigning higher values during the seasons in which
there is higher demand for energy, and lower values in seasons in which there is lower demand for
energy. The Company proposes the summer season be defined as June through September. Id.
at 11.1 The Company proposes to update the Export Credit Rate annually concurrent with the
annual update to the SAR Method on June 1. MacNeil, Di at 11.
For avoided line losses, the Company proposes to use its 2009 Analysis of System
Losses for Idaho. MacNeil, Di at 5. The Company states the study identified line losses of 4.53%
at the transmission level, 7.448% at the primary level, and 11.466% at the secondary level. Id. at
5-6. The Company states it “used the results from power flow studies to calculate a marginal loss
by load level and then fitted it to a 12 month by 24-hour profile for each of the interconnection
levels referenced above. The result is an estimate of avoided line losses that can be differentiated
by time of day and can be used to determine specific on-peak and off-peak values.” Id. at 6. The
Company proposes to credit on-site generators only for avoided primary line losses. Id. The
Company calculates the average value of avoided line losses during the 12 months ending May
31, 2021 to be $3.36 per MWh. Supplemental Application at ¶ 17.
For integration costs, the Company proposes to use the costs to integrate utility-scale
solar resources, as determined in its 2017 Flexible Reserve Study. The Company states that the
study “identifies the amount of flexible capacity required to compensate for variations in load and
resources, as well as the cost of that capacity.” MacNeil, Di at 7. After adjusting for inflation, the
Company proposes an integration of $0.64 per MWh. Id.

1 In direct testimony supporting its Original Application, the Company calculated on-peak rates during the summer
months of 3.926 cents per kilowatt-hour (“kWh”) and 3.113 cents per kWh for October through May. The Company
calculated off-peak rates of 2.183 cents per kWh for summer months and 2.356 cents per kWh for all other months.
Meredith, Di at Exhibit 5. The Company did not provide updated seasonally differentiated on-peak/off-peak rates as
part of its Supplemental Application.

ORDER NO. 34753 6
The Company proposes to move away from the monthly netting of energy imports and
exports by a customer-generator and instead calculate the customer-generator’s exports/imports
on an instantaneous basis. Meredith, Di at 15. That is, if a customer-generator is exporting at any
given moment (producing more energy than they are consuming) the customer-generator would
receive the Export Credit Rate for the energy they are exporting to the grid. If the customer-
generator is importing (consuming more energy than they are producing), at any given moment,
that customer-generator would pay the applicable retail rate for energy for the energy they are
importing from the grid. The Company proposes that export credits roll over until March of each
year for most customer-generators and until October for irrigation customers. Meredith, Di at 17.
The Company proposed to close Schedule 135 to new participants as of July 31, 2020,
and open Schedule 136 as of September 1, 2020. Both dates have been suspended by the
Commission. The Commission issued a proposed order that, if adopted, would close Schedule
135 to new participants on or after September 24, 2020, and open Schedule 136 to new participants
as of October 1, 2020. Initially, the new Schedule 136 will contain the same terms as Schedule
135, but the terms of Schedule 136 will be subject to change whereas the terms of Schedule 135
will be locked in place for 25 years if the Commission adopts the proposed order. Order No.
34752
The Company does not propose changes to retail rates for consumption in its
applications. See Supplemental Application at ¶ 2. The Company filed a Notice of Intent to File
a General Rate case on March 26, 2020. The Company later decided, due to the impacts of the
COVID-19 pandemic, to delay filing a general rate case and instead apply for an accounting order,
which would not immediately change customer rates. See Order No. 34731.
COMMENTS
A. Commission Staff.
Staff recommends the Commission order the Company to study numerous aspects of
an on-site generation program beyond what was included in the Company’s proposal, as well as
study certain aspects and assumptions of the Company’s proposal. Staff’s initial comments
identified general areas of study, and Staff’s revised comments incorporated customer concerns
and refined these general areas of study into specific questions. Staff relayed customer concerns
expressed at its June 18, 2020, live-streamed public workshop and in public comments. For
example, Staff states that customers strongly objected to the Company’s proposal for export credits

ORDER NO. 34753 7
to expire annually, proposed methods to quantify the impact of export credit expiration over
different time periods, and requested greater explanation on this issue. Staff Revised Comments.
at 12-13.
Staff provided a list of 31 questions it would like answered on a variety of topics
fundamental to on-site generation program design. Attachment A to Staff Revised Comments.
For example, Staff recommends the Commission order the Company to study the avoided capacity
value provided by customer-generators as a class either through a Loss of Load Probability method
or using a 99.5% reliability threshold. Staff Revised Comments at 9. Staff recommends the
Company study avoided transmission and distribution costs provided by customer-generators
according to methods used by the Company to calculate avoided transmission and distribution
costs for energy efficiency. Id. at 11. Staff recommends study of how the Company will recover
export credit costs through the Company’s ECAM. Id. at 7. Staff also requests study on the
Company’s use of modeled data as opposed to actual customer data. Id.
B. Idaho Clean Energy Association.
ICEA focuses its comments on the impacts to residential on-site installers and the
impacts to potential and present customer-generators. “ICEA believes that any changes to the
Company’s net metering program should be 1) understandable to solar installers and to customers;
and 2) proportional to the underlying issue that the changes are trying to address.” Id. at 2. ICEA
adds, “In the long run, simplicity, and proportionality should promote understanding and
compliance by installers and customers alike.” Id. at 2. In the vein of simplicity and
understandability, ICEA’s comments focus on the potential impacts of a move to net hourly billing.
See id. at 3. ICEA expresses an interest in smart inverters and requests that if any changes to smart
inverter requirements are to be proposed that the changes be identified and included within the
scope of the study. See id. at 4-5.
C. Idaho Conservation League.
ICL makes numerous arguments as to why it would be appropriate to defer the study.
ICL notes that Rocky Mountain Power proposes to make program changes before the conclusion
of the study. ICL Initial Comment at 2. ICL notes that the current level of participation in Rocky
Mountain Power’s on-site generation program is small based on customer-generators, exported
energy, and revenue involved, and questions whether the administrative burden of processing the
case will result in ratepayer benefits. Id. at 2-3. ICL requests delaying the study until actual data

ORDER NO. 34753 8
is available from Advanced Metering Infrastructure in the Company’s service territory, rather than
relying on modeled data. Id. at 4. Meanwhile, ICL recommends conducting a Load Research
Study like that conducted in Rocky Mountain Power’s Utah service territory. Id. ICL also requests
study of potential benchmarks to assess when market penetration will justify program design
changes. See id. at 3-4.
Like ICEA, ICL requests study on the ability of net metering service providers to
implement net hourly billing. ICL expresses concern that annual updates to the Export Credit Rate
and more granular pricing may make it extremely difficult for installers to comply with the
Residential Energy System Disclosure Act. See id. at 3. ICL also requests study of the impact to
the Idaho on-site generation market including impacts on local employment, tax revenues, and the
ability of customers to participate. Id.
ICL requests the Commission order the Company to study whether overall production
from on-site generation systems is predictable and reliable and therefore firm. See id. at 5. Instead
of using a single node on the Energy Imbalance Market to determine avoided energy costs, ICL
recommends study of Rocky Mountain Power’s actual hourly costs and comparing those costs to
the EIM data. Id. at 6. ICL recommends studying project eligibility caps based on 100% or 125%
of customer load instead of a specific kW project eligibility cap. ICL asserts that doing so complies
with prior Commission orders that define on-site generation as a means for customers to offset
their own demand. Id. at 8. ICL also recommends studying the use of smart inverters and different
smart inverter settings that can improve power quality and improve visibility of systems to the
Company. Id. In its revised comments, ICL notes that public comments identified the issue of
unused excess energy credits and their expiration. ICL Revised Comment at 2. ICL notes and
supports a customer comment requesting unused excess energy credits be donatable to other
customers unable to pay their bill. Id. at 2.
D. Rocky Mountain Power.
In its revised comments, the Company responded to public and party comments
regarding its proposal to grandfather customers and amended its proposal from 10 years to 15
years. In its reply comments, the Company addressed Staff’s proposed areas of study by either
pointing to information on the record, asserting the proposed areas of study are not properly
included in rates, agreeing an item may be appropriate for study elsewhere or at another time,

ORDER NO. 34753 9
asserting a misunderstanding, restating its proposal, or stating the Company may consider a
different proposal.
COMMISSION FINDINGS AND DECISION
The Commission has jurisdiction over this matter under Idaho Code §§ 61-502 and 61-
503. The Commission is empowered to investigate rates, charges, rules, regulations, practices,
and contracts of public utilities and to determine whether they are just, reasonable, preferential,
discriminatory, or in violation of any provision of law, and to fix the same by order. Idaho Code §§
61-502 and 61-503. The Commission may enter any final order consistent with its authority under
Title 61.
The “two-phase” approach used to process the Company’s Supplemental Application
is a new process for all parties involved. It is designed to solicit and incorporate public feedback
at pertinent stages and ensure a reasonably comprehensive study of the issues is conducted in a
credible and fair manner. The study will be one critical component of Commission review but
will not preclude the parties from introducing and the Commission considering other relevant
pieces of information when it is time to address proposals for new program implementation. The
Commission notes that the two-phase approach has offered the public adequate opportunity to
comment during the study design phase, despite difficulties associated with COVID-19.
Commission Staff and the Company each held live-streamed public workshops following their
initial comments and before submitting their revised comments. And the Commission held a
telephonic public hearing, providing customers the opportunity to comment on the record
following the initial comments and before revised comments were submitted.
Having reviewed the record, we find it reasonable to use Attachment A to Staff’s
revised comments as the basis of the ordered scope of study. We have modified Staff’s Attachment
A to reflect the proposed order on grandfathering issued concurrently recommendations from other
parties, and responses from the Company.
O R D E R
IT IS HEREBY ORDERED that Rocky Mountain Power conduct a study of on-site
generation, the scope of which is identified by Attachment A hereto.
IT IS FURTHER ORDERED that parties continue to comply with Order No. 34602,
issued March 17, 2020. All pleadings should be filed with the Commission electronically and shall
be deemed timely filed when received by the Commission Secretary. See Rule 14.02. Service

ORDER NO. 34753 10
between parties should also be accomplished electronically. Voluminous discovery-related
documents may be filed and served on CD-ROM or a USB flash drive.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date of this Order with regard to any
matter decided in this Order. Within seven (7) days after any person has petitioned for
reconsideration, any other person may cross-petition for reconsideration. See Idaho Code § 61-
626.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 26th
day of August 2020.

PAUL KJELLANDER, PRESIDENT

KRISTINE RAPER, COMMISSIONER

ERIC ANDERSON, COMMISSIONER

ATTEST:

Jan Noriyuki
Commission Secretary

I:\Legal\ELECTRIC\IPC-E-19-08\IPCE1908_scope order revised _ej
ATTACHMENT A
ORDER NO. 34753 1

Attachment A: Scope of Rocky Mountain Power’s On-Site Generation Study

Netting Period
1. Calculate the class revenue requirement if each of the existing customer-generators netted their
energy exports:
a. Monthly
b. Hourly
c. Instantaneously
2. Calculate the total class export credit payments if each of the existing customer-generators net
their energy exports:
a. Monthly
b. Hourly
c. Instantaneously
3. Analyze bill impacts to existing customer-generators, stratified by usage, if energy exports are
netted:
a. Monthly
b. Hourly
c. Instantaneously
Export Credit Rate
Modeled Data as a Proxy for Actual Customer Export Data
4. Confirm when a full year of hourly AMI export data will be available for customer-generators.
5. Explain the Company’s method for verifying and validating the accuracy of its model and
modeled customer export data.
Avoided Energy Value
6. Calculate the avoided cost of exported energy using the energy price assumptions in the
Company’s most recently acknowledged Integrated Resource Plan (“IRP”).
a. Provide supporting documentation.
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.

ATTACHMENT A
ORDER NO. 34753 2

Avoided Capacity Value
8. Analyze the capacity value of exported energy 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.
9. Provide hourly time-differentiated capacity values.
Avoided Risk
10. Analyze whether there is a fuel price guarantee value provided by on-site generators as a class.
Project Eligibility Cap
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.
Avoided Transmission and Distribution Costs
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.
Avoided Line Losses
13. Explain the avoided line loss calculations at a level that an average customer can understand.
Integration Costs
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.

ATTACHMENT A
ORDER NO. 34753 3

Avoided Environmental Costs and Other Benefits
15. Quantify the potential value of grid stability, resiliency, and cybersecurity protection provided
by on-site generators as a class and different penetration levels.
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.
17. Quantify local economic benefits, including local job creation and increased economic activity
in the immediate service territory.
18. Quantify the possible net value of Renewable Energy Credit sales produced by net metering
exported energy.
19. Quantify the reduced risk from end-of-life disposal concerns for the Company compared to
fossil-fueled resources.
Recovering Export Credit Rates in the ECAM
20. Explain the method currently used to record net metering bill credit costs.
21. Quantify the current annual amount of the net metering costs allocated to each class.
22. Present and explain how these costs have been allocated and recovered between rate classes for
the past five years.
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.
24. Analyze how these costs would be allocated and recovered by rate class through the Company’s
proposed ECAM method going forward.
Schedule 136 Implementation Issues
Billing Structure
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.
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.
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.
ATTACHMENT A
ORDER NO. 34753 4

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.
Export Credit Expiration
29. Quantify the magnitude, duration, and value of accumulated export credits as of August 1, 2020.
30. Quantify the impact to customers of a 2-year, 5-year, and 10-year expiration periods.
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.
Frequency of Export Credit Rate Updates
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).
Smart Inverter Study
33. Explain the key aspects of the Company’s Utah smart inverter policy and quantify the benefits
of applying that policy in its Idaho service territory, in particular, the potential benefits of reactive
power control.