20230914PAC to Staff 1-12.pdf

1407 W North Temple, Suite 330 Salt Lake City, Utah 84116 September 14, 2023 Jan Noriyuki Idaho Public Utilities Commission
472 W. Washington Boise, ID 83702-5918 [e-mail] (C) RE: ID PAC-E-23-17
IPUC Set 1 (1-12)
Please find enclosed Rocky Mountain Power’s Responses to IPUC 1st Set Data Requests 1-12. Also provided are Attachments IPUC 1, 3, and 10. Provided via BOX is Confidential Attachment IPUC 5. Confidential information is provided subject to protection under IDAPA
31.01.01.067 and 31.01.01.233, the Idaho Public Utilities Commission’s Rules of Procedure No.
67 – Information Exempt from Public Review, and further subject to the protective agreement executed in this proceeding. If you have any questions, please feel free to call me at [phone].

Sincerely, ____/s/____
Mark Alder
Manager, Regulation Enclosures

RECEIVED
Thursday, September 14, 2023 2:31:06 PM
IDAHO PUBLIC
UTILITIES COMMISSION
PAC-E-23-17 / Rocky Mountain Power September 14, 2023
IPUC Data Request 1
IPUC Data Request 1 For each Appendix that the Company submitted as an Excel spreadsheet, please
provide an index of the worksheets, with a narrative description of the purpose(s)
of each worksheet. If the worksheet contains raw data, please characterize the data set. For example, describe which class or classes the Company included in the data, the period covered by the data, and other unique identifiers.
Response to IPUC Data Request 1
Rocky Mountain Power (RMP) objects to this request as it seeks analysis that was not conducted by the Company. RMP further objects as this request is overly broad, unduly burdensome, and not reasonably calculated to lead to the discovery
of admissible information. Without waiving the foregoing objections, the
Company responds as follows: Please refer to Attachment IPUC 1.

Recordholder: Mark Alder Sponsor: Mark Alder

PAC-E-23-17 / Rocky Mountain Power September 14, 2023
IPUC Data Request 2
IPUC Data Request 2 Please explain the Company's plan to publish its final version of the On-Site
Generation Study (Study or Attachment No. 1), and appendices, in a format that
will be understandable by its customers and easily referenced for any subsequent discussion of an export credit rate (ECR) structure. Response to IPUC Data Request 2

The Company’s On-Site Generation Study and appendices are publicly available and can be accessed by utilizing the following website link: rockymountainpower.net/idahostudy

Note: each appendix is given its own unique name and number. Page V of the study has a list of each appendix, its name and a link to the relevant location within the study. The two confidential appendices Appendix 4.2 and Appendix 4.3 will be available to parties in this proceeding that have signed a non-
disclosure agreement.
Recordholder: Mark Alder
Sponsor: Mark Alder
PAC-E-23-17 / Rocky Mountain Power September 14, 2023
IPUC Data Request 3
IPUC Data Request 3 The narrative and tables in the Study, Section 3.2 (Class Revenue Requirement),
are not clear and difficult to follow. Please provide the following:
(a) Please re-design the explanatory narrative and the tables to better explain the information, so that a typical customer can understand it;
(b) Please provide a unique identification number for each table;
(c) Please define more clearly the columns of Table 3.1, especially column "d" (Generation); and
(d) Please restructure Table 3.2 to present the Traditional Net Metering revenue
first, followed by the hypothetical revenue for the different netting intervals. Response to IPUC Data Request 3
Rocky Mountain Power (RMP) objects as this request as vague and ambiguous as
to what a “typical customer” may understand. Without waiving the foregoing objection, the Company responds as follows: (a) Please refer to Attachment IPUC 3 which provides a redlined version of
Section 3.2 of the study that could be easier for the typical customer to
understand. (b) The tables already have unique identification numbers. While the Company considered the information below Table 3.1 to be a single table, it has split it
out into Table 3.1-a and Table 3.1-b in Attachment IPUC 3 for greater clarity
and in response to this request. (c) Please refer to Attachment IPUC 3.
(d) Please refer to Attachment IPUC 3.
Recordholder: Robert M. Meredith
Sponsor: Robert M. Meredith
PAC-E-23-17 / Rocky Mountain Power September 14, 2023
IPUC Data Request 4
IPUC Data Request 4 Please explain how the Company determined a single Integrated Resource Plan
(IRP) energy value and a single Energy Imbalance Market (EIM) energy value for
each calendar year in Table 4.1 of the Study. Please provide the data and calculations the Company used to determine these values. Response to IPUC Data Request 4

Please refer to Attachment No. 1 (Rocky Mountain Power’s On-Site Generation Study) to the Company’s Application. The referenced values reflect the expected hourly customer export profile, described in the Company’s On-Site Generation Study, specifically Section 4.2 (Model Validation Method), pages 11 through 15,
multiplied by hourly energy prices from either the Integrated Resource Plan (IRP)
or energy imbalance market (EIM), and divided by the annual customer exports. This results in a weighted average value that reflects the timing of customer exports.
For an explanation of the referenced values, please refer to Attachment No. 1
(Rocky Mountain Power’s On-Site Generation Study), specifically Section 4.3 (Avoided Energy Value), pages 15 through 20. For data and calculations, please refer to Confidential Appendix 4.2 (ID EE Cost-Effectiveness) and Confidential Appendix 4.3 (ID Export Credit Calculations).

Recordholder: Dan MacNeil Sponsor: Dan MacNeil

PAC-E-23-17 / Rocky Mountain Power September 14, 2023
IPUC Data Request 5
IPUC Data Request 5 Please recalculate Table 4.1 annual energy values using the 2023
IRP forecast energy values. Please include the underlying data and calculations.
Response to IPUC Data Request 5 Please refer to Confidential Attachment IPUC 5.

Confidential information is provided subject to protection under IDAPA 31.01.01.067 and 31.01.01.233, the Idaho Public Utilities Commission’s Rules of Procedure No. 67 – Information Exempt from Public Review, and further subject to the non-disclosure agreement (NDA) executed in this proceeding.

Recordholder: Dan MacNeil Sponsor: Dan MacNeil

PAC-E-23-17 / Rocky Mountain Power September 14, 2023
IPUC Data Request 6
IPUC Data Request 6 Please confirm that the "LOLP Gen Capacity" column in Table 4.1 of the Study is
the avoided capacity value. Please explain why the Company assigns zero value
to the "LOLP Gen Capacity" for 2021 through 2025. If this is due to a system-wide capacity deficiency date (CDD), please identify the source of the CDD determination and provide supporting documentation.
Response to IPUC Data Request 6
Confirmed. After excluding resources identified as part of the Final Short List (FSL) in PacifiCorp’s 2020 All-Source Request For Proposals (2020AS RFP) and some already committed wind repowering projects, the first major resource
additions in PacifiCorp’s 2021 Integrated Resource Plan (IRP) preferred portfolio
occur in 2026, and include wind, solar, and storage. Please refer to the 2021 IRP, Volume I, Chapter 1 (Executive Summary), page 31 which provides a summary of the near-term resource changes included in the
preferred portfolio. The 2021 IRP is publicly available and can be accessed by
utilizing the following website link: https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2021-irp/Volume%20I%20-%209.15.2021%20Final.pdf

Recordholder: Dan MacNeil Sponsor: Dan MacNeil

PAC-E-23-17 / Rocky Mountain Power September 14, 2023
IPUC Data Request 7
IPUC Data Request 7 The Company explains in Section 4.4.3 that spreading capacity compensation
across the hours with capacity shortfalls is reasonable, but doing so is more of a
rate design exercise. Study at 22. The Company therefore proposes spreading capacity value evenly across all exports. The Commission's order requested hourly time-differentiated capacity values. Please propose an alternative method that allocates the avoided capacity value only to critical capacity hours.
Response to IPUC Data Request 7 Please refer to Attachment No. 1 (Rocky Mountain Power’s On-Site Generation Study) to the Company’s Application. Confidential Appendix 4.2 (ID EE Cost-
Effectiveness) provides hourly time-differentiated capacity values, specifically
tab “Calc”, column P. For details on the timing of loss of load events (LOLE) from PacifiCorp’s 2021 Integrated Resource Plan (IRP) analysis, please refer to Confidential Appendix
4.2 (ID EE Cost-Effectiveness), specifically tab “LOLP”. This information is
also shown in Figure 4.2 (Weighted LOLP Distribution) in the On-Site Generation Study. LOLE can be categorized in four periods:

• Summer evenings: 59 percent of events, June through September between 4 p.m. and 12 a.m. Pacific Time (PT), with 55 percent occurring between 4 p.m. and 10 p.m. PT.

• Summer nights: 17 percent of events, June through September between 12 a.m. and 8 a.m. PT.
• Winter: 17 percent of events, December through February between 6 a.m. and 9 p.m. PT.
• Summer days: 7 percent of events, June through September between 8 a.m.
and 4 p.m. PT.
As shown above, more than half of all LOLE are expected to occur between 4 p.m. and 10 p.m. PT, therefore, it is a possible definition of critical capacity hours; however, only 2.6 percent of customer exports are expected to be delivered
during this timeframe. The loss of load probability (LOLP) generation capacity
value in 2026 shown in Table 4.1 (Summary of Export Credit Costs) was 0.40 cents per kilowatt-hour (cents/kWh), paid to all customer exports. To provide that same compensation only for exports between 4 p.m. and 10 p.m. PT, the price during that time period would need to be multiplied by 38.3 (100 percent / 2.6
PAC-E-23-17 / Rocky Mountain Power September 14, 2023
IPUC Data Request 7
percent). This would result in a generation capacity price of 15.17 cents/kWh during critical capacity hours (and a generation capacity price of zero in other hours). Please refer to the Company’s response to IPUC Data Request 5,
specifically Confidential Attachment IPUC 5, tab “LOLP” which provides the
associated calculations. Note: this method allocates all capacity value to the defined critical capacity hours, even though lower levels of risk occur in other periods. Differentiating energy value in the same period definition might also be appropriate.

While the proposal above would focus on the most critical hours, if an export credit price for customer-generators were to be time differentiated, aligning with the time periods used for retail rate schedules such as Schedule 36 would be preferred, since keeping a consistent definition would reduce customer confusion.
Additionally, billing system and metering constraints should be considered.
Recordholder: Dan MacNeil / Robert Meredith
Sponsor: Dan MacNeil / Robert Meredith
PAC-E-23-17 / Rocky Mountain Power September 14, 2023
IPUC Data Request 8
IPUC Data Request 8 The Company's determination of avoided capacity value uses a weighted Loss of
Load Probability (LOLP) distribution based on a forecasted 2030 test period.
Please replicate the avoided capacity valuation using the LOLP for 2026, the first CDD year. Please replicate the avoided capacity valuation using actual export contributions for 2022.
Response to IPUC Data Request 8
Loss of load probability (LOLP) analysis is extremely data intensive, and the Company has not prepared LOLP values for 2026. The Company does have LOLP values available for 2024 and 2028, based on the 2021 Integrated Resource
Plan (IRP) preferred portfolio, and an average of the LOLP values for these two
years could represent a reasonable estimate for 2026. The capacity contribution of the export profile is higher based on the 2026 LOLP estimate and would result in a price of 0.66 cents per kilowatt-hour (cents/kWh), up from 0.40 cents/kWh based on 2030 LOLP data. Please refer to the Company’s response to IPUC Data
Request 5, specifically Confidential Attachment IPUC 5, tab “LOLP 2026” which
provides the associated calculations. The Company does not have an estimate of actual export contributions for 2022.

Recordholder: Dan MacNeil Sponsor: Dan MacNeil

PAC-E-23-17 / Rocky Mountain Power September 14, 2023
IPUC Data Request 9
IPUC Data Request 9 In the Study section on netting period, the Company considers the administrative
costs of data processing at a 15-minute netting interval. Please answer the
following questions: (a) Please explain if the Company considered the administrative burden under other netting intervals.

i. If yes, please provide the corresponding netting interval and estimate for hours of Company activity. ii. If not, why not?

(b) Please explain if the Company quantified the administrative benefit that the Company expects under an instantaneous billing export credit rate structure. Response to IPUC Data Request 9

(a) The Company only has experience with 15-minute interval and instantaneous netting. The Company believes that hourly netting would carry the same administrative burden as 15-minute interval netting. Since instantaneous netting uses the same metering information as traditional net metering, there is
no difference in administrative burden between these two netting intervals.
The Company does not have experience with monthly netting. Monthly netting would require changes to its billing system that the Company has not quantified.
(b) Please refer to the Company’s response to subpart (a) above.
Recordholder: Robert M. Meredith
Sponsor: Robert M. Meredith
PAC-E-23-17 / Rocky Mountain Power September 14, 2023
IPUC Data Request 10
IPUC Data Request 10 Please answer the following questions regarding the Model Validation section of
the Company's Study:
(a) The Company describes that Idaho customer-generators have shifted from wind systems to solar photovoltaic (PV) systems. Please provide the current distribution of customer-generators by technology type (i.e., solar, solar plus
battery, wind, etc.) for the residential, small commercial, large commercial,
and irrigation sectors separately for both Idaho and the Northern Utah Proxy group; (b) Please explain if the Company examined any other potential sources of bias
(i.e. systematic difference between the Utah proxy and Idaho on-site
generation population) and describe why the Company did not include them in the study; (c) On page 15, the Company states that its analysis indicates that the overall
difference in hourly export profiles between northern Utah customers and
Idaho will be small. Please provide this analysis and accompanying work papers; (d) If not shown in the analysis, please describe how the Company uses identified
sources of bias to adjust the model and provide supporting work papers that
show the calculation; and (e) Please explain what state and regulatory policy considerations the Company accounted for when comparing the Utah proxy group.
Response to IPUC Data Request 10 (a) Please refer to Attachment No. 1 (Rocky Mountain Power’s On-Site Generation Study) to the Company’s Application, specifically Table 2.1
(Idaho On-site Generation Customer Count as of 12/31/2022) for the
distribution of Idaho customer-generators by class and system type. Please refer to Attachment IPUC 10 which provides customer counts by class and system type for the Utah proxy group as of December 31, 2022.
(b) As discussed in Section 4.2 of the Rocky Mountain Power’s (RMP) On-Site
Generation Study, the Company examined possible bias between the Utah proxy and Idaho on-site generation customers based on differences in system size, monthly exports and hourly production as potential sources of bias. Sampling bias was also considered and ultimately determined to not exist,
while metering error was also considered and was determined to be negligible.
No other sources of bias were considered.
PAC-E-23-17 / Rocky Mountain Power September 14, 2023
IPUC Data Request 10
(c) The Company concluded that the difference in hourly exports in Idaho and the Utah proxy group will be small based on the comparison of rated capacity,
actual monthly exports and simulated photovoltaic (PV) system production.
This analysis generally showed differences of less than 10 percent. Please refer to RMP’s On-Site Generation Study, Appendix 4.4 (Idaho Export Profile Validation Avg Capacity), Appendix 4.5 (ID Export Profile Validation Monthly Exports) and Appendix 4.6 (ID Export Profile Validation PV Watts
Production) for additional detail.
(d) The Company did not adjust the export profile derived from the Utah proxy group.
(e) The Company recognizes that Utah proxy customers in the On-Site
Generation Study take service through Utah Electric Service Schedule 136, while Idaho customers take service through both Idaho Electric Service Schedule 135 (Net Metering Service) and Idaho Electric Service Schedule 136 (Net Billing Service). Although the rate structures differ between both groups,
the Company’s analysis illustrated that monthly exports are similar for both
Utah and Idaho customers. Recordholder: Lee Elder / Mark Alder

Sponsor: Lee Elder / Mark Alder
PAC-E-23-17 / Rocky Mountain Power September 14, 2023
IPUC Data Request 11
IPUC Data Request 11 Please answer the following questions regarding chapter five of the
Study:
(a) The Company states that it "... estimated maximum non-coincident peak is 8.4kW for the typical residential customer taking service on Schedule 1 and 11.5 kW for the typical residential customer taking service on Schedule 1."
Study at 23. Please clarify to which schedule the provided non-coincident
peaks are referring; (b) Please provide any analysis that the Company performed when considering demand-based project eligibility cap;

(c) Please describe what peak load data the Company considered to determine a hypothetical demand-based project eligibility cap; (d) Please describe what alternative methods the Company considered to
determine a hypothetical demand-based project eligibility cap if appropriate
historical demand data is unavailable; and. (e) Please explain if the Company considered any alternate project eligibility cap structure other than demand-based and/or current caps.
Response to IPUC Data Request 11 (a) The referenced text contained a typographic error and should have read that “estimated maximum non-coincident peak is 8.4kW for the typical residential
customer taking service on Schedule 1 and 11.5 kW for the typical residential
customer taking service on Schedule 36". (b) The Company did not perform any additional analysis on this issue beyond what it shared in the report.

(c) Please refer to the Company’s response to subpart (b) above. (d) The Company did not determine any alternative methods for determining a project eligibility cap.

(e) The Company did not consider an alternate project eligibility cap structure. Recordholder: Robert M. Meredith

Sponsor: Robert M. Meredith
PAC-E-23-17 / Rocky Mountain Power September 14, 2023
IPUC Data Request 12
IPUC Data Request 12 In chapter six of the Study, the Company establishes that the capacity contribution
for Transmission and Distribution (T&D) system deferral is different from the
generation capacity contribution based on system LOLP. Please answer the following questions: (a) Please explain if the Company considered other methodologies to determine
the value of avoided T&D costs. If yes, please describe these methodologies
and why the Company did not include them in Study; (b) Please identify the specific information that the Company expects it would need to estimate the avoided T&D costs based on T&D capacity needs;

(c) Please explain if the Company considered new small commercial, large commercial, or irrigation projects as it did for new residential projects; and (d) Please describe if the Company analyzed past Idaho specific T&D project
costs to estimate the value of avoided T&D cost.
Response to IPUC Data Request 12 (a) The most comprehensive avoided transmission and distribution (T&D)
methodology would consider whether specific upcoming T&D needs in Idaho
could be deferred or avoided altogether as a result of Idaho customer exports. For example, when looking at substations that have loads approaching their capacity ratings, if the peaks are during the daytime in the summer, it could be an indication that exports could reduce peak demand sufficiently to avoid the
need for an upgrade. However, if load is growing on that circuit, it might
outpace customer exports and the upgrade would be required in the next few years anyway. Similarly, if load is relatively flat on the circuit, i.e. both day and night, customer exports would not allow the upgrade to be avoided. Finally, given customer exports are likely to represent a statewide program,
targeting customer exports exclusively to those circuits that could benefit from
a T&D perspective would be difficult. The calculation presented in Attachment No. 1 (Rocky Mountain Power’s On-Site Generation Study) to the Company’s Application incorporates the overall loading of the distribution system in Idaho to help represent the likelihood that any given location in
Idaho will require distribution system upgrades.
(b) The following information would likely be necessary to evaluate individual T&D deferral opportunities as a result of customer generation exports:
1. Capacity (i.e. rating) of limiting T&D elements.
2. Projected costs for limiting T&D elements.
PAC-E-23-17 / Rocky Mountain Power September 14, 2023
IPUC Data Request 12
3. Peak loading, with hourly detail. 4. Projected load growth, both rate of increase and potential block load additions.
5. Customer generation potential for that load pocket or circuit.
6. Other distributed resource potential that could supplement customer generation, for instance energy efficiency (EE), demand response (DR) and / or distributed battery resources.
(c) The T&D credit used in PacifiCorp’s Integrated Resource Plan (IRP) is
applied to EE programs for all customer classes and is not specific to residential customers. The Company has not specifically evaluated export profiles for the referenced types of Idaho customers and has no information about their relative suitability for T&D savings.

(d) The T&D credit used in the 2021 IRP is based on the forecasted cost of planned T&D capacity additions in the next few years from throughout PacifiCorp’s service territory and includes a small number of projects located within the state of Idaho as part of the overall data set. The same project cost
per kilowatt ($/kW) of transmission and distribution capacity is used for all
states, as the sample size is relatively small, and the cost can vary widely based on the individual circumstances.
Recordholder: Dan MacNeil / Mark Alder
Sponsor: Dan MacNeil / Mark Alder

1
Joe Dallas (ISB #10330) 825 NE Multnomah, Suite 2000 Portland, OR 97232 Telephone No. [phone]
Email: [e-mail] Attorney for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
TO
-SITE CUSTOMER

-E-23-17
LITY

I, Joe Dallas, represent Rocky Mountain Power in the above captioned matter. I am an
attorney for Rocky Mountain Power.
I make this certification and claim of confidentiality regarding the response to the attached
Idaho Public Utilities Commission Staff discovery request pursuant to IDAPA 31.01.01 because
Rocky Mountain Power, through its response, is disclosing certain information that is Confidential
and/or constitutes Trade Secrets as defined by Idaho Code Section 74-101, et seq. and 48-801 and
protected under IDAPA 31.01.01.067 and 31.01.01.233. Specifically, Rocky Mountain Power
asserts the Company’s response to IPUC Data Requests Nos. 5 contain Company proprietary
information that could be used to its commercial disadvantage.
Rocky Mountain Power herein asserts that the aforementioned responses contain
confidential in that the information contains Company proprietary information.
2
I am of the opinion that this information is “Confidential,” as defined by Idaho Code
Section 74-101, et seq. and 48-801, and should therefore be protected from public inspection,
examination and copying, and should be utilized only in accordance with the terms of the
Protective Agreement in this proceeding.

DATED this 14th day of September, 2023.

Respectfully submitted,

By__________________________
Joe Dallas Senior Attorney Rocky Mountain Power
Appendix Index
Name of
Appendix Description

Data Set Characterization
Appendix 3.1:
Idaho NEM Class
Production
Comparison of generation to exports under
the following netting scenarios: monthly,
hourly, instantaneous, and traditional.
2022 customer generators taking
service on residential schedule 1,
residential schedule 36, general
service schedule 23, and general
service schedule 6
Appendix 4.1:
Export Profile
Jan21-Dec22
Export profile for calendar years 2021 and
2022 from Utah Schedule 136 customers

Exports are measured in both 15
min and hourly periods for both
2021 and 2022.
CONF Appendix
4.2: ID EE Cost-
Effectiveness
Capacity contribution based on average
exports 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 Loss of Load Probability (“LOLP”). A
summary of the export credit costs are
provided on the summary sheet.
Capacity contribution analyses
CONF Appendix
4.3: ID Export
Credit
Calculations
Evaluation of historical customer generation
exports and the top 10 percent load
conditions over the past two years, spanning
2021-2022
Various export credit analyses

Appendix 4.4:
Idaho Export
Profile Validation
Avg Capacity
Average installed capacity for solar PV
systems for Idaho customers and Utah
Schedule 136 customers in climate zone 6B.
Data is as of December 31, 2022
Appendix 4.5: ID
Export Profile
Validation
Monthly Exports
Average monthly export comparison - Idaho
and Utah Sch 136 climate zone (CZ) 6B
Calendar year 2022
Appendix 4.6: ID
Export Profile
Validation PV
Watts Production
Export profile comparison - Idaho and Utah
Sch 136 climate zone (CZ) 6B
PVWatts for calendar year 2022
Appendix 4.7:
Appendix K -
Capacity
Contribution -
2021 IRP
Appendix K from PacifiCorp’s 2021 Integrated
Resource Plan (IRP) explaining PacifiCorp’s
capacity contribution and methodology.
N/A
Name of
Appendix Description

Data Set Characterization
Appendix 8.1:
Appendix F -
Flexible Reserve
Study- 2021 IRP
Appendix F from PacifiCorp’s 2021 Integrated
Resource Plan (IRP) explaining PacifiCorp’s
flexible reserve study.
N/A
Appendix 8.2:
Wind and Solar
Integration
Charges
Approved in
Order No. 34966
The wind and solar integration charges
approved in Order No. 34966 in PacifiCorp’s
application to update the wind/solar
integration rate for small power generation
facilities in Case No. PAC-E-20-14.
N/A
Appendix 11.1:
Weighted
Average
Overproduction
The weighted average of the annual
compensation for Idaho on-site generation
customers
The weighted average was
calculated for residential, small
commercial, large commercial,
and irrigation customers. The
average compensation for each
customer class was calculated by
dividing the total annual
compensation by the number of
on-site generators for each year.
Appendix 11.2:
Idaho Expired
Credit Analysis
2012-2022
Idaho on-site generator customer credit by
year and schedule
2-, 5-, and 10-year periods were
evaluated for on-site residential,
small commercial, large
commercial, and irrigation
customers
Appendix 11.3:
Customer Impact
at 2-, 5-, and 10-
Year Expiration
Sample of the overproducing customers
generation calculated to show the value of
credits that could be subject to expiration
over the 2-, 5-, and 10-Year Expiration time
periods
The 10-year analysis looked at
2013-2022, the 5-year analysis
evaluated 2018-2022, and the 2-
year analysis evaluated 2021-2022
Appendix 11.4:
SAR Export Credit
Analysis
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
SAR export credit rates were
evaluated with effective dates
from 2012-2023.
Appendix 12.0:
Utah STEP -
Smart Inverter
Study
Final report of Electric Power Research
Institute (EPRI)’s study on “Advancing Smart
Inverter Integration in Utah”
N/A

4 | P a g e

3.2 Class Revenue Requirement
The tables and analysis below address Study Scope Item 1.

Study Scope Item 1
Calculate the class revenue requirement if each of the existing customer-generators netted
their energy exports:
a. Monthly
b. Hourly
c. Instantaneously

To estimate the revenue requirement or difference in revenue for each of the different ways
that energy could be netted that are listed for the Study, the Company analyzed the monthly
billing and metering data from customer-generators in 2022. 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 data available for
customer-generators in Idaho. Instead, the Company used estimated hourly 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 values, the differences by month from the Northern
Utah data for each netting type were applied to metered data from actual Idaho customer-
generators. The following table 3.1-a shows how net exported energy would change under
different netting-types and table 3.1-b shows how much those net exported energy amounts
are as a percentage of overall customer generated energy:
5 | P a g e

Table 3.1-a: Comparison of Exported Energy under Different Netting Types to Customer
Generated Energy
kWh a. Exported
Energy
(Monthly
Netting)
b. Exported
Energy (Hourly
Netting)
c. Exported
Energy
(Instantaneous
Netting)
d. Customer
Generated Energy
Residential Sch 1 2,111,780 8,062,620 8,554,724 16,422,970
Residential Sch 36 551,492 2,058,027 2,182,649 4,124,398
General Service Sch 23 244,599 534,099 565,335 1,512,638
General Service Sch 6 58,760 116,414 123,320 522,963
Total 2,966,631 10,771,161 11,426,028 22,582,969
Table 3.1-b: Exported Energy under Different Netting Types as a Percentage of Customer
Generated Energy
Export % of Generation a. Monthly
Netting
b. Hourly
Netting
c. Instantaneous
Netting
d.
Generation
Residential Sch 1 13% 49% 52% 100%
Residential Sch 36 13% 50% 53% 100%
General Service Sch 23 16% 35% 37% 100%
General Service Sch 6 11% 22% 24% 100%
Total 13% 48% 51% 100%

To estimate the revenue impact by customer group for different netting types, the Company
estimated the change in revenue from traditional net metering. Increased revenue from each
customer group lowers the overall revenue needed from that group. Assuming a generic 3¢ per
kWh export credit price, the Company estimates the following change in revenue needed from
traditional net metering for the different netting types:
6 | P a g e

Table 3.2: Revenue Changes from Traditional Net Metering
Revenue a. Traditional
Net Metering
b. Monthly
Netting
c. Hourly
Netting
d. Instantaneous
Netting
Residential Sch
1
$1,090,937 $1,253,784 $1,716,364 $1,756,739
Residential Sch
36
$333,476 $384,917 $462,434 $468,933
General Service
Sch 23
$141,635 $156,402 $172,883 $174,728
General Service
Sch 6
$295,469 $296,204 $296,925 $297,011
Total $1,861,517 $2,091,307 $2,648,606 $2,697,411
Change in
Revenue
Needed from
Traditional Net
Metering
-$229,791 -$787,089 -$835,895

Based on the information shown in Table 3.2 above, monthly netting would result in a $230k
reduction in the revenue needed when compared with traditional net metering, meaning that
an additional $230k would be collected from customer generators and not required from other
customers. Hourly netting would see a larger $787k reduction and instantaneous netting would
see a $836k reduction in the revenue needed when compared with traditional net metering.
Class Solar PV Wind Mixed/Other Total
Residential 1,418 0 1 1,419
Small Commercial 32 0 0 32
Large Commercial 20 0 0 20
Irrigation 1 0 0 1
Total Count 1,471 0 1 1,472
Utah Proxy Group - Count