20231106PAC to Staff 14-38.pdf

1407 W North Temple, Suite 330 Salt Lake City, Utah 84116
November 6, 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 3 (14-38) Please find enclosed Rocky Mountain Power’s Responses to IPUC 3rd Set Data Requests 14-38. Also provided are Attachments IPUC 15-2 and 29. Provided via BOX is Confidential Attachments IPUC 15-1, 24, and 34. 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
Monday, November 6, 2023 2:10:04 PM
IDAHO PUBLIC
UTILITIES COMMISSION
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 14
IPUC Data Request 14 Please explain the basis the Company used to decide which terms it included in the On-Site Generation Study (Study) glossary.
Response to IPUC Data Request 14 The Company included a definition of terms in its glossary to help the average
reader better understand the study. The Company selected terms that may be
unfamiliar or unclear to the average reader. Recordholder: Mark Alder
Sponsor: Mark Alder
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 15
IPUC Data Request 15 Please provide all 2021 Integrated Resource Plan (IRP) work papers used to support the Study appendices.
Response to IPUC Data Request 15 Please refer to Confidential Attachment IPUC 15-1 and Attachment IPUC 15-2.
Note: for ease of review, within Confidential Attachment IPUC 15-1, the
Company is providing copies of the appendices with links to the provided work papers intact. 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 November 6, 2023 IPUC Data Request 16
IPUC Data Request 16 Table 2.1 provides a breakdown of the on-site generation types. Please identify how many of the systems include battery storage.
Response to IPUC Data Request 16 As of December 31, 2022, there were 140 systems with batteries. Of the 140 all
were solar photovoltaic (PV) of which 136 were residential and four were small
commercial. Recordholder: Tony Worthington \ Jessica Patton \ Jayne Grim
Sponsor: Tony Worthington
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 17
IPUC Data Request 17 In section 3.0 of the Study, the Company explains the effects of monthly, hourly, and instantaneous netting intervals. However, Table 3.4 presents a fourth option,
'Traditional Net Metering.' Please explain the difference between Monthly Netting
and Traditional Net Metering. Response to IPUC Data Request 17

The difference between “Monthly Netting” and “Traditional Net Metering” is that the excess exported kilowatt-hour (kWh) credit is at the illustrative price of 3 cents/kWh for “Monthly Netting” and the monthly excess exported kWh credit is at either actual retail rates or calculated rates based on the actual Mid-Columbia (Mid-C) Intercontinental Exchange (ICE) index prices, depending upon rate
schedule, for “Traditional Net Metering”.
Recordholder: James Zhang

Sponsor: Robert M. Meredith
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 18
IPUC Data Request 18 Table 3.4 presents the bill impacts for customers with different average consumptions (the "Average Bill" column). Please clarify if the average
consumption categories are average monthly consumption, or annual
consumption. Please clarify if the average consumption categories are net imports or full imports. Please provide a breakdown of how many customers are in each of the groups.
Response to IPUC Data Request 18 The average consumption categories in Table 3.4 are average monthly billed kilowatt-hours (kWh) which is equal to the larger of net kWh (delivered - exported) and zero kWh for each bill.

Recordholder: James Zhang
Sponsor: Robert M. Meredith
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 19
IPUC Data Request 19 Please describe any alternative means considered by the Company for determining the value of customer-exported energy besides the IRP energy
forecast and the Energy Imbalance Market hourly historic pricing. If there were
any, please list the reason(s) the Company rejected those alternatives. Response to IPUC Data Request 19

One alternative energy value is to use hourly prices from the one of the market points in the Company’s forward price curves (FPC). For a discussion of the FPC, please refer to PacifiCorp’s 2021 Integrated Resource Plan (IRP), Volume I, Chapter 8 (Modeling and Portfolio Evaluation Approach) on pages 227-228. PacifiCorp’s 2021 IRP is publicly available and can be accessed by utilizing the following website link:

Integrated Resource Plan (pacificorp.com) A second alternative energy value is to use the Standard Avoided Resource (SAR)
methodology approved for standard qualifying facility (QF) contracts in Idaho, which
uses the variable costs of a proxy combined-cycle gas plant and primarily based on the cost of natural gas. Natural gas prices are forecasted on a monthly basis as part of the Company’s FPC described above. There are no significant market points in the vicinity of the Company’s Idaho loads,
so there is a potential disconnect with the value of exports within the Company’s
Idaho service territory. In addition, the FPC represents the cost of firm transactions, done in advance of delivery, so these market prices are not representative of non-firm customer-exports. The Company sees significant swings in market prices across the
day and throughout the year, often well above and well below the variable cost of a
combined-cycle gas plant. Market prices are often lower in the spring, when hydro run-off is high and load is relatively low. Market prices are also typically lower during the day as a result of zero-cost supply from solar generation across the west, as this reduces the need to call on more expensive resources that might otherwise set market prices. A combined-cycle gas plant would typically operate at a reduced level
or even be shut off when market prices were below its variable costs, as this allows
for more load to be served with lower cost energy supplies from the market. Because customer-exported energy is most commonly received from customer-sited solar, factoring in the typical periods of delivery can have a significant impact on the value, and this isn’t reflected in the SAR methodology.
Recordholder: Dan MacNeil Sponsor: Dan MacNeil
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 20
IPUC Data Request 20 Please describe any alternative means considered by the Company for distributing the value of customer-exported energy on a seasonal time variant basis, as
opposed to a flat annual rate. If there were any alternatives, please list the
reason(s) the Company rejected them. Response to IPUC Data Request 20

The Company discussed the potential for differentiating credits for customer-generated exports within its response to Study Scope Item 26 in Rocky Mountain Power’s (RMP) On-Site Generation Study (Attachment No. 1 to the Company’s application).
While the Company primarily presented flat annual values in the export credit
results, Confidential Appendix 4.2 (ID EE Cost-Effectiveness) to RMP’s On-Site Generation Study could be adapted to identify values for more granular periods, including distinct seasons or time-of-day. As discussed in the response to Study
Scope Item 26 identified above, sending appropriate price signals to customers
while limiting the potential for confusion are key considerations. Technical limitations related to billing and metering systems can also factor into how rates are able to be applied. The Company is open to working with stakeholders to develop an export credit program that balances these considerations.

Recordholder: Dan MacNeil / Robert Meredith Sponsor: Dan MacNeil / Robert Meredith

PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 21
IPUC Data Request 21 Please describe any alternative means considered by the Company for determining the value of avoided generation capacity costs besides the Capacity
Factor approximation method. If there were any alternatives, please list the
reason(s) the Company rejected them. Response to IPUC Data Request 21

Referencing’s Attachment No. 1 (Rocky Mountain Power’s (RMP) On-Site Generation Study), Section 4.4.2 (Historical Peak Conditions) identifies exceedance levels for customer exports relative to the top 10 percent Idaho load hours and the top 10 percent system load hours. The associated calculations are provided in Confidential Appendix 4.3 (ID Export Credit Calculations) to RMP’s
On-Site Generation Study. The Study Scope identified a reliability threshold of
99.5 percent, while the Company presented results at various levels. The Company maintains a fleet of resources to serve customers, and individual resources are unlikely to have 99.5 percent reliability. A variety of resources
working together can achieve high reliability despite even if some of those
resources experience forced outages or can only reduce reliability risks during certain periods. In addition, while high load is one factor in generation capacity needs, as solar resources become more prevalent, the Company has found that the highest net load requirements, after the sun has set, are becoming a bigger driver of the need for additional generation capacity.

Confidential Appendix 4.2 (ID EE Cost-Effectiveness) to RMP’s On-Site Generation Study also provided an estimate of avoided capacity costs using the hours with the highest marginal energy prices (column K, tab “Calc”). High
energy prices can indicate that available resources are scarce, which might
coincide with periods with potential loss of load conditions. Marginal energy prices can be volatile from year-to-year and are heavily impacted by the portfolio resource mix in a given year along with market prices for electricity and natural gas. To the extent market prices are setting marginal energy prices, high prices could be indicators of supply and demand risks in other areas, i.e. outside the
Company’s system, so they might not be as representative of the Company’s
avoided generation capacity costs. Recordholder: Dan MacNeil Sponsor: Dan MacNeil
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 22
IPUC Data Request 22 Please describe the Company's policies regarding the use of Effective Load Carrying Capability calculations for generation resources.
Response to IPUC Data Request 22 Please refer to PacifiCorp’s 2021 Integrated Resource Plan (IRP), Volume II,
Appendix K (Capacity Contribution) which provides a discussion of capacity
contribution methodologies. PacifiCorp’s 2021 IRP is publicly available and can be accessed by utilizing the following website link: Integrated Resource Plan (pacificorp.com)
Given the scale of the Company’s system and the variety of resource options and
locations available, the Company tends to focus capacity contribution analysis on the time periods in which loss of load risks are expected to occur. These risks can be calculated in a single stochastic study, and the results can be applied to
resource options and locations throughout the Company’s system using the
Capacity Factor Approximation Methodology (CF Method), described in Appendix K referenced above. Because of the complexity of the Company’s system, performing a stochastic study for a one-year period can require up to a week of model runtime to produce sufficient stochastic iterations.
In contrast, the Effective Load Carrying Capability (ELCC) requires at least two
stochastic studies, to determine the load carrying capability both with and without a generation resource under consideration. In practice, achieving the same level of reliability under both cases typically requires some fine-tuning, and/or
interpolation of multiple results, to produce an estimate of the ELCC. Additional
stochastic studies would be required for each additional generation resource under consideration. Because of synergistic and antagonistic impacts between different resource types, such as benefits from combining solar and storage, studies with combinations of resources could produce different, and potentially more relevant, results. Because of the computational requirements of the ELCC methodology,
the Company tends not to use it.
Recordholder: Dan MacNeil
Sponsor: Dan MacNeil
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 23
IPUC Data Request 23 Please explain why the Company proposes using 2030 as the test yearn.
Response to IPUC Data Request 23
The Company assumes that the statement “test yearn” is intended to be a reference to the “test year”. Based on the foregoing assumption, the Company
responds as follows:
Attachment No. 1 (Rocky Mountain Power’s (RMP) On-Site Generation Study) only uses a 2030 test year for the generation capacity contribution estimate. This value is multiplied by avoided generation costs in various years to get avoided cost estimates over a 20-year horizon. 2030 was the only year in which loss of
load probability (LOLP) results were produced as part of PacifiCorp’s 2021
Integrated Resource Plan (IRP) and reflects a midpoint of the 2021-2040 study horizon used in the 2021 IRP.

Recordholder: Dan MacNeil Sponsor: Dan MacNeil

PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 24
IPUC Data Request 24 In its response to Production Request No. 8, the Company declined to provide the avoided capacity valuation for 2022 because "[t]he Company does not have an
estimate of actual export contributions for 2022." Although Staff is aware that
Idaho customer export data was not available for 2022, please provide the following:
(a) The avoided capacity valuation for 2022 using the same Utah proxy data that
the Company used for the Study in this case; and (b) An overview of how much avoided capacity valuation can change (and why) depending on the test period.
Response to IPUC Data Request 24
(a) Capacity contribution estimates based on loss of load probability (LOLP) analysis described in Attachment No. 1 (Rocky Mountain Power’s (RMP) On-
Site Generation Study), Section 4.4.1 (Loss of Load Probability Study) reflect
Utah average proxy data from 2021-2022 and LOLP for 2030. Please refer to the Company’s response to IPUC Data Request 23. 2030 was the only year for which LOLP results were produced in PacifiCorp’s 2021 Integrated Resource Plan (IRP). The Company does not have a way to calculate the actual LOLP for each hour in 2022.

For LOLP-based capacity contribution results using the 2030 LOLP data from the 2021 IRP and only actual data for 2022 from the available Utah proxy data (rather than average data for 2021-2022), please refer to Confidential
Attachment IPUC 24. The impact of using only 2022 data is negligible, an
increase from 2.98 percent to 3 percent. (b) In general, avoided capacity values vary, as a result of portfolio changes. For example, as more solar resources are added to a portfolio, the capacity contribution of solar declines. The same effect would be seen as storage
becomes a larger portion of a portfolio, with longer storage durations
necessary to achieve the same level of capacity contribution. Capacity values could also be impacted by changes in patterns of load, for example due to climate change, building electrification, or electric vehicle (EV) charging. Ultimately, a new generation resource will contribute some level of capacity to the system throughout its operating life, and different combinations of new resources are to be required over time to compensate for retirements/expiring contracts as well as evolving capacity contribution levels for the rest of the portfolio.
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 24
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 November 6, 2023 IPUC Data Request 25
IPUC Data Request 25 In section 5.0 of the Study, the Company provided justification for leaving the existing Project Eligibility Cap in place for residential customers. However, the
Company did not address the other classes with on-site generation, especially
those with a 100-kilowatt cap, as requested by the Commission. Please provide the pros and cons for the omitted classes.
Response to IPUC Data Request 25
The purpose of customer generation programs like net metering and net billing are for customers to offset their own energy consumption with onsite renewable generation. For large levels of generation, such as generators with over 100 kilowatts (kW) of nameplate capacity, compensation through avoided costs is
more accurate and appropriate. Large onsite generators may receive this
compensation by becoming a qualifying facility and contracting with the Company for the sale of its output. A benefit to keeping the non-residential cap at 100 kW is that it ensures that larger installations would receive more accurate
avoided cost pricing for the value of their generator’s output. One downside of
keeping the existing non-residential cap is the added administrative effort that may be required for a customer with a larger level of generation to become a qualifying facility.
Recordholder: Robert M. Meredith
Sponsor: Robert M. Meredith

PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 26
IPUC Data Request 26 In section 6.0 of the Study, the Company states that its "...evaluation of energy efficiency measures includes assumed deferral of local transmission and
distribution upgrades." (Emphasis added). Staff interprets this to mean that the
energy efficiency program uses a value for avoided transmission and distribution (T&D) costs. However, the report does not provide this value, and the ensuing comments discuss other issues, leaving this possibility unanswered. Please clarify
this section of the report.
Response to IPUC Data Request 26 The avoided transmission and distribution upgrade costs assumed to be applicable to energy efficiency (EE) were identified in PacifiCorp’s 2021 Integrated
Resource Plan (IRP), Volume I, Chapter 7 (Resource Options) in Table 7.10
(State-specific Transmission and Distribution Credits). PacifiCorp’s 2021 IRP is publicly available and can be accessed by utilizing the following website link:
Integrated Resource Plan (pacificorp.com)
For details on the calculation of these costs, please refer to confidential file “Table 7.10 State-specific Transmission and Distribution Credits CONF.xlsx” provided with the Company’s response to IPUC Data Request 15, specifically in Confidential Attachment IPUC 15-1.

Recordholder: Dan MacNeil
Sponsor: Dan MacNeil
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 27
IPUC Data Request 27 In section 6.0 of the Study, the Company states that the avoided T&D cost is "likely to differ" from the avoided generation cost. However, the Company
applies the avoided generation capacity contribution of 3.0 percent anyway,
without explanation. Please clarify why this is appropriate. Also, the Company provides a final value of $1.10/MWh without identifying where the reader can find the underlying calculations. Please describe where to find the calculations.
Response to IPUC Data Request 27 The avoided transmission and distribution capacity value calculations is provided in Confidential Appendix 4.2 (ID EE Cost-Effectiveness) to Attachment No. 1 to the Company’s Application (Rocky Mountain Power’s (RMP) On-Site Generation
Study). Please refer to cells M25 and N25 for the respective values for
transmission capacity and distribution capacity which sum to $1.10 per megawatt-hour ($/MWh).

Recordholder: Dan MacNeil Sponsor: Dan MacNeil

PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 28
IPUC Data Request 28 Please describe any alternative means considered by the Company for distributing the value of avoided T&D costs on a seasonal time variant basis, as opposed to a
flat annual rate. If there were any alternatives, please list the reason(s) the
Company rejected them. Response to IPUC Data Request 28

Please refer to the Company’s response to IPUC Data Request 20. Recordholder: Dan MacNeil
Sponsor: Dan MacNeil
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 29
IPUC Data Request 29 In section 7.0 of the Study, the Company refers to its 2018 Line Loss Study. Please provide a searchable version of that study.
Response to IPUC Data Request 29 Please refer to Attachment IPUC 29 which provides a copy of the 2018 Line Loss
Study referred to in Section 7.0 of Rocky Mountain Power’s (RMP) On-Site
Generation Study. Recordholder: Ray Baise
Sponsor: Lee Elder
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 30
IPUC Data Request 30 In section 7.0 of the Study, the Company omits consideration of transformer core losses. Please explain whether the Company intends to adjust the line loss factors
for transformer core losses or not. Please explain the Company's reason(s) for
either including or excluding them. Response to IPUC Data Request 30

The Company’s 2018 Line Loss Study measured all losses from generator input to customer delivery at three different voltage levels, therefore transformer core losses are included within the totals identified. Referencing Rocky Mountain Power’s (RMP) On-Site Generation Study
(Attachment No. 1 to the Company’s application), Study Scope Item 13 requested
an explanation at a level that an average customer can understand. The provided explanation of electrical resistance accounts for most of the losses without including overly complicated detail.

Recordholder: Dan MacNeil Sponsor: Dan MacNeil

PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 31
IPUC Data Request 31 Please explain why the Company included pages in Appendix 8.2 beyond the first two pages because they appear to be unreadable and not relevant to the Study.
Response to IPUC Data Request 31 Referencing Rocky Mountain Power’s (RMP) On-Site Generation Study
(Attachment No. 1 to the Company’s application), Appendix 8.2 (Wind and Solar
Integration Charges Approved in Order No. 34966) should have been limited to the first two pages as the remaining pages relate to qualifying facility (QF) rates and are not specific to integration costs. Recordholder: Dan MacNeil

Sponsor: Dan MacNeil

PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 32
IPUC Data Request 32 In section 9.1.1 of the Study, the Company describes the Wattsmart Batteries program in effect in Utah. Please discuss the impact this program might have on
the proxy Utah export profile. Please provide any supporting analysis.
Response to IPUC Data Request 32
Of the 1,472 customers in the Utah proxy group only 34 have storage (~2.3
percent). Given the low penetration of storage in the Utah proxy group, the Wattsmart batteries program was unlikely to have a significant impact on the export profile. To the extent that customers add both batteries and solar, the expectation would
be that charging of batteries would result in reduced exports, particularly in the
middle of the day when solar output was high. Customers can generally maximize the value of a battery by avoiding retail rates, and discharging only up to the customer’s load, i.e. battery discharging would reduce load served by the utility
but would not result in exports in those hours that would show up in the export
profile. Recordholder: Dan MacNeil
Sponsor: Dan MacNeil
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 33
IPUC Data Request 33 Please clarify the Company's position regarding Schedule 135 - Net Metering Service customers with respect to section 11.0.
Response to IPUC Data Request 33 Since Schedule 135 is closed to applications for new service as of October 2,
2020, the Company is not planning to make any changes to this schedule in the
near future. Recordholder: James Zhang
Sponsor: Robert M. Meredith
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 34
IPUC Data Request 34 In section 11.1.1 of the Study, the Company recommends seasonal export credit pricing, but not time-of-day pricing. Please provide the following:

(a) Examples of how pricing would vary under different seasonal scenarios and time of-day scenarios;
(b) A description of the advantages and disadvantages of each scenario; and
(c) The underlying worksheets for these examples. Response to IPUC Data Request 34
(a) Please refer to Confidential Attachment IPUC 34 which provides two examples of
seasonal time-of-day rates: based on the Schedule 36 definition (effective June 1, 2025) and an alternative definition with a single four-hour on-peak definition applicable year-round. Either example can be customized to reflect a different season or time-of-day
definition, by modifying highlighted cells on tab “Season-TOU Definition”.
(b) The Schedule 36 definition is already applicable to some customers therefore it could potentially be familiar to them already, i.e. they may have set various heating or cooling schedules accordingly or would only have to account for one schedule. Using an existing definition can also ensure that billing and metering can be accomplished in a
straightforward and potentially less-expensive manner.
In both examples, “on-peak” export volumes are relatively low, particularly with the four-hour definition. It might still be appropriate to have such definitions if particular
customers have a significantly higher exports within those periods, for example
customers with wind generators. The rates would encourage additional adoption of higher value resources. However, if most customers would receive similar levels of compensation regardless of the selected definition, it may not provide sufficient benefits to justify the complexity for customers interpreting it and the Company billing it.
(c) Please refer to the Company’s response to subpart (a) above.
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 November 6, 2023 IPUC Data Request 35
IPUC Data Request 35 In section 11.1.2 of the Study, the Company's input does not address the Commission's order, which states, "[p]lease explain how customer-generators will
have accurate and adequate information to make informed choices about the
economics of onsite generation over the expected life of the system." Order No. 34753. Please discuss any informational assistance the Company may offer to help customers evaluate the economics of on-site generation. Please discuss the
trade-offs of a fixed export credit rate versus one that varies, either frequently or
infrequently. Response to IPUC Data Request 35 The Company respectfully disagrees that Section 11.1.2 (Economic Evaluation
for Customer-Generators and On-Site Generation System Installers) of Rocky
Mountain Power’s (RMP) On-Site Generation Study (Attachment No. 1 to the Company’s application) does not address the Idaho Public Utilities Commission’s (IPUC) order. As noted in the study, the Company will be able to provide
prospective customer generators with the ability to view hourly historic usage
data online which would allow a customer to analyze how the output of generation may align with usage. However, customers who are considering adopting onsite generation should do their due diligence. The trade-off between a fixed export price versus an export price that changes more frequently is one of accuracy versus customer certainty. An export credit price that changes annually
will more accurately compensate customer generators for the value of their
exported energy than an export credit price that remains fixed for a multi-year period but would provide customer generators with less certainty. The Company notes that annual updates to the export credit price may benefit customer
generators, since a fixed multi-year export credit price may miss particular years
where the value of exported energy is higher. The Company also notes that its net billing program in Utah, which has been in place since 2020, utilizes annual price updates.
Recordholder: Robert M. Meredith
Sponsor: Robert M. Meredith
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 36
IPUC Data Request 36 In section 11.2.2 of the Study, the Company's input misinterprets the Commission's order, which states, "[q]uantify the impact to customers of a 2-year,
5-year, and 10-year expiration periods [sic]." Please answer this same question
with the understanding that the expiration periods are projecting forward into the future, and not backward into the past. Please discuss whether kilowatt-hour credits should expire or not.
Response to IPUC Data Request 36 First, the Company would note that the monetary value of the export credit rate in the period the exports occur is potentially appropriate to roll forward as a credit. The value of kilowatt-hours (kWh) would vary from year-to-year in actual
operation (as well as with annual export credit rate updates) and could potentially
vary by season or time-of-day, depending on how the rates are structured. For example, referencing Rocky Mountain Power’s (RMP) On-Site Generation Study (Attachment No. 1 to the Company’s application), specifically Table 4.1
(Summary of Export Credit Costs), the energy imbalance market (EIM) energy
values (which make up the majority of the total value) jumped from 2.83 cents per kilowatt-hour (¢/kWh) in 2021 to 4.35 ¢/kWh in 2022, an increase of 54 percent.
Excess customer exports in 2021 would not reduce the cost of serving customers
in 2022 and kWh credits that are shifted into future periods would not provide
value to the system that is representative of the cost in those future periods. The expiration analysis provided in the On-Site Generation Study, Appendix 11.2 (Idaho Expired Credit Analysis 2012-2022) was based on existing credit rates for the various customer classes, which reflects retail charges. Based on the estimates
in Table 4.1 of the On-Site Generation Study, it appears likely that updated export
credit rates would be somewhat below the current rates in Schedule 136 upon which the analysis in Section 11.2.2 of Appendix 11.2 was based. If the Idaho Public Utilities Commission (IPUC) established an export credit rate that was
lower than retail charges, the likelihood of a customer having excess credits
would decrease, as more exports would be necessary to offset each increment of a customer’s retail purchases. The analysis in Section 11.2.2 of Appendix 11.2 indicated that very few customers would have significant credits at risk of expiration. It might be more appropriate for such customers to seek an alternative structure, such as a Public Utility Regulatory Policies Act of 1978 (PURPA)
contract, to manage their excess supply.
Recordholder: Dan MacNeil
Sponsor: Dan MacNeil
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 37
IPUC Data Request 37 In section 11.2.3 of the Study, the Company discusses export credit expiration policy. Please answer the following:

(a) Both the Commission Order and the Company's response are ambiguous about the term "credits." Please clarify if the Company's response contemplates kilowatt-hour credits or financial credits;

(b) If the Company is proposing that financial credits expire, please explain why they should expire. Please explain why the Company should not pay the customer for any unused financial credits (c) Please discuss how customers can utilize their financial credits, and if
customers can be paid for financial credits; and
(d) Please clarify the Company's proposed timing for the use and expiration of both kilowatt-hour credits and financial credits.
Response to IPUC Data Request 37 (a) The Company's response in Section 11.2.3 (Export Credit Expiration Policy) of Rocky Mountain Power’s (RMP) On-Site Generation Study (Attachment No. 1 to the Company’s application) contemplates financial credits;

(b) Please refer to Section 11.2.3 (Export Credit Expiration Policy) of Rocky Mountain Power’s (RMP) On-Site Generation Study in which the Company explains why the financial credits should expire and why the Company should
not pay the customer generator for any unused financial credits.
(c) Please refer to the discussion in Section 11.2.3 (Export Credit Expiration Policy) of RMP’s On-Site Generation Study. (d) The Company proposes an annual timing for the use and expiration of both
kilowatt-hour (kWh) credits and financial credits.
Recordholder: James Zhang Sponsor: Robert M. Meredith
PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 38
IPUC Data Request 38 In section 11.3 of the Study, the Company recommends that it update the ECR annually. Please provide a table that lists all the components of the ECR, the
proposed source of data for determining each component, and the proposed
update frequency for each component. Please discuss the reasons for each proposed update frequency.
Response to IPUC Data Request 38
Referencing Rocky Mountain Power’s (RMP) On-Site Generation Study (Attachment No. 1 to the Company’s application), a discussion of the timing considerations for each of the export credit components listed in Table 4.1 (Summary of Export Credit Costs) is provided below:
Energy – energy value is by far the largest component of the export credit rate, representing roughly 80 percent to 90 percent of the total value, and is also reflected in losses and risk value, as these are percentage adders to the energy
value. Because of the inherent alignment between energy imbalance market
(EIM) actual prices and the timing of actual customer exports, the Company is in favor of using actual data, in particular because it is granular, readily available, and public. As a result, updated export profile information would also be part of the annual update. By updating energy value annually to apply values from a recent completed historical period to the upcoming rate effective period, values
would lag somewhat, but should be reasonably representative of export credit
values over time. Losses – line loss rates are typically updated in general rate case (GRC)
proceedings. The Company would recommend using line loss assumptions based
on the study used in the most recent completed GRC. While line loss rates would remain in place until superseded in a future GRC, the actual value would vary with changes in energy prices, and would also flow into generation capacity value, which could change independently. Generation Capacity – this value requires two inputs: generation capacity cost
and capacity contribution. Capacity contribution using the Capacity Factor Approximation Methodology (CF Method) in turn requires loss of load probability (LOLP) data as well as export profile data. Both generation capacity cost and LOLP data would be identified in the Company’s Integrated Resource Plan (IRP), which is produced every two years. Historical export credit profiles would be available annually from the energy value calculation, but for simplicity, generation capacity rates could be updated using recent export credit profiles after IRP filing or acknowledgment and held fixed (other than inflation) until the next IRP.

PAC-E-23-17 / Rocky Mountain Power November 6, 2023 IPUC Data Request 38
Transmission Capacity - this value requires two inputs: transmission capacity cost and capacity contribution and would generally have similar considerations as those described for generation capacity, with updates after each IRP.
Distribution Capacity - this value requires two inputs: distribution capacity cost
and capacity contribution and would generally have similar considerations as those described for generation capacity, with updates after each IRP.
Risk – this value is a percentage of the energy value and would be calculated
from risk analysis conducted within the IRP, therefore it would be appropriate to update the risk percentage after each IRP, while the resulting value would update with each energy update. Integration Cost – each IRP includes an estimate of solar integration costs, with
values by year. The stream of annual estimates would be updated after each IRP,
while between IRPs values would change each year to reflect the value specific to the upcoming rate-effective period.

Recordholder: Dan MacNeil Sponsor: Dan MacNeil