20220209PAC to Staff 1-38.pdf

February 9, 2022
Jan Noriyuki [e-mail] (C) Riley Newton
[e-mail]
RE: ID PAC-E-21-19 IPUC Set 1 (1-38)
Please find enclosed Rocky Mountain Power’s Responses to IPUC’s 1st Set Data Requests 6, 8, 12-14, 16-19, and 31-38. The remaining responses will be provided separately. Also providedare Attachments IPUC 26 and 29. Provided via BOX are Confidential Attachments IPUC 17 and36.Confidential information is provided subject to protection under IDAPA 31.01.01.067 and31.01.01.233, 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.
If you have any questions, please feel free to call me at [phone].
Sincerely,
____/s/____
J.Ted Weston
Manager, Regulation
Enclosures C.c.: Rose Monahan/Sierra Club [e-mail] (C)Ana Boyd/Sierra Club [e-mail] (C) Benjamin J. Otto/ICL [e-mail]
RECEIVED
2022 FEB 09 PM 4:47
IDAHO PUBLIC
UTILITIES COMMISSION
PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 6
IPUC Data Request 6 There is no question 6 in this set.
Response to IPUC Data Request 6
There was no question 6 submitted in IPUC Set 1. There is no response to provide.

Recordholder: Not Applicable Sponsor: Not Applicable

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 8
IPUC Data Request 8 2021 Integrated Resource Plan (IRP) Please provide the financial impact on Idaho from removing Bridger 1 and 2 from
Washington's allocation by the end of Q4 2023.
Response to IPUC Data Request 8
Absent an agreement between states and Commission approval of a limited
realignment, as discussed in Section 6.4 of the 2020 Protocol, there would be no financial impact on Idaho from removing Jim Bridger Unit 1 and Jim Bridger Unit 2 from Washington’s allocation by the end of Q4 2023. Idaho would continue to be allocated only their applicable share of Jim Bridger Unit 1 and Jim Bridger Unit 2 costs and/or benefits.

Recordholder: Nick Highsmith
Sponsor: Nick Highsmith

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 12
IPUC Data Request 12 2021 Integrated Resource Plan (IRP) Please describe in detail project specifics and costs of pumped hydro listed in the
New Storage Resources section of the IRP. (Volume I - Chapter 9, page 295).
Response to IPUC Data Request 12
Please refer to the confidential data disk accompanying PacifiCorp’s 2021
Integrated Resource Plan (IRP), specifically folder “Confidential\ST Studies CONF.zip\ST Studies\CETA”, file “ST Cost Summary -P02-MMGR-CETA ST Split Run Cost Data LT 18609 ST 19709”, tab “Generator Cost” and filter column D (“Child Name”) on “HYS.PX.YAK._._PS.BM”.
For the setup of the pumped hydro storage resources in the PLEXOS model,
please refer to the confidential data disk accompanying the 2021 IRP, specifically folder “Plexos Inputs CONF.zip\Plexos Inputs”, file “Plexos Inputs - 2021 IRP 091021_CONF”, tab “Properties” and filter column C (“Child Object”) for the
pumped hydro storage resource “HYS.PX.YAK._._PS.BM”.
For the supply side table which lists pumped storage projects, please refer to the confidential data disk accompanying PacifiCorp’s 2021 IRP, specifically folder “Chapters and Appendices CONF.zip\Chapters and Appendices CONF\Chapter 7 - Resource Options”, file “Table 7.1-7.2 Total Resource Cost for Supply-Side
Resource Options 21 IRP”
Recordholder: Dan Swan

Sponsor: Shay LaBray
PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 13
IPUC Data Request 13 2021 Integrated Resource Plan (IRP) Please provide the "expert third-party natural gas price forecast" used in Aurora.
(Volume I - Chapter 8, page 227).
Response to IPUC Data Request 13
Please refer to the non-confidential / public data disk accompanying PacifiCorp’s
2021 Integrated Resource Plan (IRP), specifically folder “Input Assumptions\Price Curves” and, for example, file “Endur Price V9 03.31.2021 East-West Spreadsheet MM.xlsx” for the reported monthly natural gas and electric prices.

Recordholder: Dan Swan Sponsor: Shay LaBray

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 14
IPUC Data Request 14 2021 Integrated Resource Plan (IRP) Please provide the source of data used in Figure 8.5 for Natural Gas Prices.
(Volume I - Chapter 8, page 228).
Response to IPUC Data Request 14
Please refer to the Company’s response to IPUC Data Request 13 which provides
the location of the data used in PacifiCorp’s 2021 Integrated Resource Plan (IRP), Volume I, Chapter 8 (Modeling and Portfolio Evaluation Approach), Figure 8.5 (Nominal Wholesale Electricity and Natural Gas Price Scenarios), specifically for “Natural Gas Prices”, “Henry Hub”.

Recordholder: Dan Swan Sponsor: Shay LaBray

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 16
IPUC Data Request 16 2021 Integrated Resource Plan (IRP) Please provide information regarding the source of natural gas for the converted
Jim Bridger units 1 and 2 and copies of any pipeline or futures contracts that are
in place to supply the converted units with natural gas. Response to IPUC Data Request 16

The Company has received bids from natural gas pipeline companies in close proximity to the Jim Bridger Plant. Negotiations are on-going; no contract(s) have been executed.
Recordholder: Stephen Fendrich / Irene Heng
Sponsor: To Be Determined

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 17
IPUC Data Request 17 2021 Integrated Resource Plan (IRP) Please provide a copy of the Company's risk management policy and specifics on
natural gas hedging.
Response to IPUC Data Request 17
Please refer to Confidential Attachment IPUC 17 which provides copies of the
following most current PacifiCorp policy documents:
• PacifiCorp’s Energy Risk Management Policy dated July 1, 2021.
• PacifiCorp’s Front Office Procedures dated December 22, 2021.
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: John Fritz / Paul Wood
Sponsor: John Fritz / Paul Wood
PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 18
IPUC Data Request 18 2021 Integrated Resource Plan (IRP) Please answer the following questions regarding Table 5.8:

(a) Please explain how the Front Office Availability Limits values at each hub in
both Summer and Winter in the 2021 IRP are determined and provide work papers to support the explanation. (b) Please explain why these availability limit assumptions remain the same throughout the entire IRP horizon. (c) Page 253 of the 2021 Integrated Resource Plan Volume I states that the preferred portfolio includes the Energy Gateway South transmission line. Page 133 states the transmission line can connect into the Mona market hub. Page
324 states that construction of the transmission line is expected to be
completed and placed in service in 2024. Does the Availability Limit assumption for Mona hub consider the Gateway South transmission line? Please explain. (d) Page 253 of the 2021 Integrated Resource Plan Volume I states that the
preferred portfolio includes Boardman-to-Hemingway transmission line, which will come online in 2026. Does the Availability Limit assumption for Mid-C consider the Boardman-to-Hemingway transmission line? Please explain.
Response to IPUC Data Request 18 (a) Please refer to PacifiCorp’s 2021 Integrated Resource Plan (IRP), Volume I, Chapter 5 (Reliability and Resiliency), page 114 for the discussion on determining “Front Office Availability Limits”.

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 18
(b) Front office transaction (FOT) limits do not change over the model horizon because the Company has no basis to assume the timing of resources retiring in the future that are not announced as well as new resource planned additions in the Western Electricity Coordinating Council (WECC) over the IRP study
period, other than the Company’s 2021 IRP. The “Front Office Availability
Limits” forecast is based on best available information. (c) No, the “Front Office Availability Limits” does not consider PacifiCorp
transmission rights related to specific transmission projects, as these
availability limits are based on an assessment of market depth and liquidity at the markets. The Company notes that FOTs are defined for the peak months of June and December (as indicated in Table 5.8 in the 2021 IRP) and do not change over
the 20-year horizon in those months. However, transmission changes can
impact purchases and sales limits in non-peak months, which are otherwise not subject to the FOT limits and are constrained by available transmission.
(d) No, the “Front Office Availability Limit” at Mid-Columbia (Mid-C) does not
consider the Boardman-to-Hemingway (B2H) transmission line addition as it does not connect to the Mid-C market in PacifiCorp’s 2021 IRP topology and does not affect market depth.
Recordholder: Dan Swan
Sponsor: Shay LaBray

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 19
IPUC Data Request 19 2021 Integrated Resource Plan (IRP) Page 135 of the 2021 Integrated Resource Plan Volume I states that PacifiCorp
evaluated the resources available relative to the expected load in every hour, and
the hour with the lowest resources as a percentage of the hourly load each season determines the planning reserve margin (PRM) achieved for that season in that year. Page 135 also mentions a minimum 13 percent PRM target. Please answer
the following questions:
(a) Please confirm that the seasonal PRM is identified and used in the 2021 IRP to determine the minimum 13 percent PRM target. If not, please explain how the seasonal PRM is used in the 2021 IRP.
(b) Also, please explain step by step how a 13 percent PRM target is determined.
Response to IPUC Data Request 19
(a) Confirmed. The seasonal resource planning contribution is identified and used
in PacifiCorp’s 2021 Integrated Resource Plan (IRP) to assess whether it meets the minimum 13 percent planning reserve margin (PRM) target. (b) The 2019 IRP informed the 13 percent PRM. Please refer to the 2019 IRP, Volume II, Appendix I (Planning Reserve Margin Study) where the
methodology and selection is described. Also, please note the footnote on
page 146 which still applies, “A PRM below 13 percent would not sufficiently cover the need to carry short-term operating reserve needs (contingency and regulating margin) and longer-term uncertainties such as extended outages
and changes in customer load. PacifiCorp must hold approximately six
percent of its resources in reserve to meet contingency reserve requirements and an estimated additional 4.5 percent to 5.5 percent of its resources in reserve, depending upon system conditions at the time of peak load, as regulating margin. This sums to 10.5 percent to 11.5 percent of operating reserves before even considering longer-term uncertainties such as extended
outages (transmission or generation) and customer load growth”.
Recordholder: Dan Swan Sponsor: Shay LaBray
PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 20
IPUC Data Request 20 2021 Integrated Resource Plan (IRP) Page 154 and Page 155 show the Summer Peak System Capacity Loads and
Resources without Resource Additions. Please answer the following questions:
(a) Please explain how capacity contribution for each of the different types of resources are determined for purposes of identifying the capacity deficiency
date.
(b) Please explain the purpose of the CF Methodology discussed in Appendix K and how the results are used in the IRP. (c) Please confirm that the CF Methodology discussed in Appendix K is not used
in determining the first deficit year.
Response to IPUC Data Request 20
(a) The Company discusses this topic in its 2021 Integrated Resource Plan (IRP),
Volume I, Chapter 6 (Load and Resource Balance) on page 149. For the 2021 IRP, PacifiCorp evaluated the balance of generating capability and load obligations not just during the coincident peak load hour, but across all hours, to identify the winter and summer hours in each year with the lowest margin as a percentage of load. Under this method, the reported planning reserve
margin is necessarily met in the coincident peak (CP) load hour, but the hour
with the lowest margin generally coincides with a period of relatively high load and relatively low renewable resource output. After identifying the planning reserve margin (PRM) associated with the portfolio of resources, any
remaining requirement necessary to achieve a 13 percent PRM would have to
come from front office transactions (FOT), i.e. market purchases. To the extent this exceeded the available FOT limits, additional resources would be required. This analysis is hourly, and based on the portfolio as a whole. Renewable
resources contribute to the total resource supply in every hour that they
provide generation, though some hours are more important than others. While the hour with the lowest margin as a percentage of load ultimately determines the reported PRM, reporting resource output in this hour alone would ignore the contributions of other resources in many other hours, without which the portfolio would have had an even lower margin. With this in mind, the Company did not attempt to calculate a capacity contribution specific to the hour with the lowest margin. Assigning a capacity contribution based on that hour would not have changed the reliability of the portfolio. Instead, for purposes of reporting the load and resource balance, capacity contribution was
assigned to resources in the manner discussed on page 150 in Chapter 6, with
PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 20
greater capacity value assigned to resources available in hours with relatively high loads and relatively low available resources. (b) The capacity factor approximation method (CF Method) discussed in the 2021
IRP, Volume II, Appendix K (Capacity Contribution) provides a snapshot of
the relative contribution to reliable system operation of different resource types. Specifically, the CF Method identifies the extent to which a resource’s output coincides with periods in which loss of load would be likely to occur.
This analysis was based on a portfolio similar to the preferred portfolio in
calendar year 2030, and any difference in that portfolio would impact the results. (c) Correct.

Recordholder: Dan MacNeil Sponsor: Shay LaBray

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 21
IPUC Data Request 21 2021 Integrated Resource Plan (IRP) Please answer the following questions regarding Front Office Transactions in
Table 6.11, Table 6.12, and Table 6.13:
(a) Please confirm that "Available Front Office Transactions" are based on the values of the Availability Limits in Table 5.8.

(b) Response to Staff Production Request No. 13 in Case No. PAC-E-20-13 states that the term "uncommitted FOTs to meet remaining need" refers to the amount of FOTs, up to the "available front office transactions" that could be used to meet a capacity deficit in the initial load and resource balance. Please explain why "Uncommitted FOTs to meet remaining Need" in the summers of
2021, 2022, and 2023 are greater than "Available Front Office Transactions"
as shown in Table 6.11 in the 2021 Integrated Resource Plan Volume I. Response to IPUC Data Request 21

Note: the Company takes an opportunity to clarify that there is no “Table 6.13” in the official published version of PacifiCorp’s 2021 Integrated Resource Plan (IRP), Volume I, Chapter 6 (Load and Resource Balance). The Company’s responses to IPUC Data Request 21 are therefore only referencing Table 6.11 (Summer Peak – System Capacity Loads and Resources without Resource
Additions) and Table 6.12 (Winter Peak System Capacity Loads and Resources
without Resource Additions). (a) Confirmed. The “Available Front Office Transactions” limits in the PLEXOS
model are based on the information provided in the 2021 IRP, Volume I,
Chapter 5 (Reliability and Resiliency), Table 5.8 (Maximum Available Front Office Transactions by Market Hub). (b) The “Uncommitted FOTs to meet remaining Need” in 2021 through 2023 are greater than "Available Front Office Transactions" due to the need to balance
the system. Since there are no proxy resources allowed in the period 2021
through 2023, the Company will be reliant on a higher level of front office transactions (FOT) in the near term. Recordholder: Dan Swan Sponsor: Shay LaBray
PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 22
IPUC Data Request 22 2021 Integrated Resource Plan (IRP) The footnote of Table 6.10 states "[d]ue to the timing of the 2021 IRP load
forecast, there is a small amount of (68 MW) of existing Class 2 DSM in Table
6.12 (System Capacity Loads and Resources without Resource Additions)". Please answer the following questions:
(a) What Class 2 DSM program corresponds to the 68 MW program?
(b) Is the program reflected in Line "Existing - Energy Efficiency" in Table 6.11, Table 6.12, and Table 6.13? If so, why are the values in Line "Existing – Energy Efficiency" smaller than 68 MW and why do the values vary every year?

(c) Please explain the timing issue that caused the 68 MW program to not be included in the load forecast.
(d) Would listing the 68 MW existing energy efficiency as a separate line achieve
the same effect as including it in the Line "Load"? Please explain. (e) Page 151 states that due to timing issues with the vintage of the load forecast, there is a level of 2020 energy efficiency (73 MW) that is not incorporated in the forecast. Please reconcile the 68 MW and the 73 MW.

(f) Please confirm that Line "New Energy Efficiency" in Table 6.11, Table 6.12, and Table 6.13 represents energy efficiency programs selected in the portfolio development process as resource options.

(g) Please explain why new demand response programs are not included in Table 6.11, Table 6.12, and Table 6.13, while "New Energy Efficiency is included. Response to IPUC Data Request 22
Note: the Company takes an opportunity to clarify that there is no “Table 6.13” in
the official published version of PacifiCorp’s 2021 Integrated Resource Plan (IRP), Volume I, Chapter 6 (Load and Resource Balance). The Company’s responses to IPUC Data Request 22 are therefore only referencing Table 6.11 (Summer Peak – System Capacity Loads and Resources without Resource Additions) and Table 6.12 (Winter Peak System Capacity Loads and Resources without Resource Additions). (a) The 68 megawatts (MW) correspond to the portfolio of programs offered in Idaho; PacifiCorp’s 2021 IRP assumed the Class 2 demand-side management
(DSM), “Existing Energy Efficiency” were based the 2020 program savings
PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 22
estimates at the time the inputs for the 2021 IRP were finalized. (b) The 68 MW of existing energy efficiency (EE) is included in the 67.5 MW (rounded up to 68 MW) listed in Table 6.11 and Table 6.12. The peak
contributions of the existing EE can vary from year-to-year because the hourly
load profile and hourly load net of all EE selections changes from year-to-year.
(c) This timing issue occurs because 2020 is the first year of forecast within the
load forecast used in the 2021 IRP. EE potential selections are made for the 2021 through 2040 time frame in the IRP planning process. Therefore, the existing 2020 EE selections must be accounted for in the IRP. (d) The 68 MW is listed as a separate line that is netted against the load when
determining the total obligation, therefore yes, it would have the same effect if
it was deducted from the line “Load”. (e) The 73 MW listed in the 2021 IRP, Volume I, Chapter 6 (Load and Resource
Balance), section “Energy Efficiency (Class 2 DSM)” on page 151 was
incorrect. It should have been correctly stated as 68 MW. (f) Yes, “New Energy Efficiency” line in each of Table 6.11 and Table 6.12 does represent the EE selected in the portfolio development process.
(g) The “New Energy Efficiency” line in each of Table 6.11 and Table 6.12 is
included in the “System Capacity Loads and Resources without Resource Additions” (Table 6.11 and Table 6.12) because EE represents an actual reduction in loads and is not a dispatchable resource. Demand response (DR)
is a dispatchable resource and therefore was not included in these tables that
intended to report System Capacity Loads and Resources without Resource Additions. Recordholder: Brian Osborn

Sponsor: Shay LaBray
PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 23
IPUC Data Request 23 2021 Integrated Resource Plan (IRP) Page 148 of the 2021 Integrated Resource Plan Volume I states that PacifiCorp
obtains the remainder of its capacity and energy requirements through long-term
firm contracts, short-term firm contracts, and spot market purchases. Please explain whether long- term firm contracts and short-term firm contracts are assumed to be renewed in the load and resource balances in Table 6.11, Table
6.12, and Table 6.13 and why.
Response to IPUC Data Request 23 Note: the Company takes an opportunity to clarify that there is no “Table 6.13” in the official published version of PacifiCorp’s 2021 Integrated Resource Plan
(IRP), Volume I, Chapter 6 (Load and Resource Balance). The Company’s
responses to IPUC Data Request 23 are therefore only referencing Table 6.11 (Summer Peak – System Capacity Loads and Resources without Resource Additions) and Table 6.12 (Winter Peak System Capacity Loads and Resources
without Resource Additions).
Long-term firm (LTF) contracts and short-term firm (STF) contracts are not renewed in the 2021 IRP but expire upon the contract termination date. There is no guarantee the resources are available when the contract terminates and pricing is unknown. These contracts do not have rollover rights or options.

Recordholder: Dan Swan
Sponsor: Shay LaBray

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 24
IPUC Data Request 24 2021 Integrated Resource Plan (IRP) Please explain whether PURPA contracts are assumed to be renewed in the load
and resource balances in Table 6.11, Table 6.12, and Table 6.13 and why. Response to IPUC Data Request 24
Note: the Company takes an opportunity to clarify that there is no “Table 6.13” in
the official published version of PacifiCorp’s 2021 Integrated Resource Plan (IRP), Volume I, Chapter 6 (Load and Resource Balance). The Company’s responses to IPUC Data Request 24 are therefore only referencing Table 6.11 (Summer Peak – System Capacity Loads and Resources without Resource Additions) and Table 6.12 (Winter Peak System Capacity Loads and Resources
without Resource Additions).
In the 2021 IRP, the only existing qualifying facilities (QF) that the Company assumes will renew their contracts are for cogeneration facilities associated with
large industrial loads that are represented in the load forecast on an ongoing basis.
The absence of generation by these facilities would imply a material change in customer operations and the Company’s load. Other QF power purchase agreements (PPA) do not extend in the 2021 IRP and expire upon the contract termination. There is no guarantee the resource continues
beyond the contract termination date, and pricing is unknown.
Recordholder: Dan Swan

Sponsor: Shay LaBray
PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 25
IPUC Data Request 25 2021 Integrated Resource Plan (IRP) Page 149 of the 2021 Integrated Resource Plan Volume I states that the hourly
system load is reduced by hourly private generation projections to determine the
net system coincident peak load for each of the first ten years (2021-2030) of the planning horizon. Please explain why the hourly system load is reduced by hourly private generation projections only for the first ten years, instead of for the entire
planning horizon. Response to IPUC Data Request 25 In PacifiCorp’s 2021 Integrated Resource Plan (IRP), Volume I, Chapter 6 (Load and Resource Balance), section “Capacity and Energy Balance Overview”, page
149, the reference to “the first ten years (2021-2030) of the planning horizon” was
incorrectly stated. The correct reference should have been that the hourly system load is reduced by hourly private generation (PG) projections for the 20 years of the IRP planning horizon (2021 through 2040).

Recordholder: Dan Swan Sponsor: Shay LaBray

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 26
IPUC Data Request 26 2021 Integrated Resource Plan (IRP) Page 149 of the 2021 Integrated Resource Plan Volume I states the load and
resource balances use assumed coal unit retirements from the preferred portfolio.
Please answer the following questions: (a) Please confirm that Table 6.11, Table 6.12, and Table 6.13 are based on the
assumed coal unit retirements from the preferred portfolio. (b) Please list the early retirement dates of each coal unit. (c) Please list the original retirement dates of each coal unit if early retirements are not assumed and the sources of the determinations.
Response to IPUC Data Request 26 Note: the Company takes an opportunity to clarify that there is no “Table 6.13” in
the official published version of PacifiCorp’s 2021 Integrated Resource Plan
(IRP), Volume I, Chapter 6 (Load and Resource Balance). The Company’s responses to IPUC Data Request 26 are therefore only referencing Table 6.11 (Summer Peak – System Capacity Loads and Resources without Resource Additions) and Table 6.12 (Winter Peak System Capacity Loads and Resources without Resource Additions).

(a) Confirmed. Table 6.11 and Table 6.12 are based on the coal unit retirements from the 2021 IRP preferred portfolio.
(b) Please refer to Attachment IPUC 26 which provides the end of life (EOL) coal
retirement dates and the PLEXOS retirement dates in the 2021 Preferred Portfolio. Note: Jim Bridger Unit 1 and Jim Bridger Unit 2 are converted to natural gas in 2024. (c) The EOL retirement dates are from the Company’s most current depreciation
study and have not changed from the 2019 IRP. Minority owned plant
retirements are based on current information. Recordholder: Dan Swan Sponsor: Shay LaBray
PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 27
IPUC Data Request 27 There is no question 27 in this set.
Response to IPUC Data Request 27
There was no question 27 submitted in IPUC Set 1. There is no response to provide.

Recordholder: Not Applicable Sponsor: Not Applicable

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 28
IPUC Data Request 28 2021 Integrated Resource Plan (IRP) Page 149 of the 2021 Integrated Resource Plan Volume I states that the energy
balance shows the average monthly surplus or deficit of energy over the first ten
years of the planning horizon (2021-2030). Please explain why only the first ten years, instead of the entire planning horizon, is included.
Response to IPUC Data Request 28
The energy balance is reported over the first 10 years of the 2021 Integrated Resource Plan (IRP) planning horizon (2021 through 2030) which is a near term view. The focus is on the early years since the energy balance is reporting average monthly surplus or deficit of energy based on existing resources. This gives an
indication of where the energy deficit occurs and the magnitude before expansion
resource additions. Extending the forecast would show larger energy deficits as existing resources retire or contracts expire, as would be expected. Beyond the 10-year period the focus is on expansion resource additions and less about existing
resource deficits.
Recordholder: Dan Swan Sponsor: Shay LaBray

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 29
IPUC Data Request 29 2021 Integrated Resource Plan (IRP) Page 152 of the 2021 Integrated Resource Plan Volume I discusses Demand
Response in the load and resource balances. Please answer the following
questions regarding Demand Response: (a) Besides "interruptible contracts", what other programs are included in
"Existing - Demand Response" category in Table 6.11, Table 6.12, and Table
6.13? (b) What category is energy storage included in the load and resource balances in Table 6.11, Table 6.12, and Table 6.13?
(c) How are the values in Line "Existing - Demand Response" determined? (d) Page 152 states that PacifiCorp has had interruptible contracts for approximately 177 MW of load interruption capability for many years. Please
provide capacity values of interruptible contracts for each year for summer and
winter and explain how the values are determined. (e) Please explain why Demand Response (Class 1 DSM) is listed as a resource in the 2019 IRP but is listed as a reduction to load in the 2021 IRP.
Response to IPUC Data Request 29
Note: the Company takes an opportunity to clarify that there is no “Table 6.13” in the official published version of PacifiCorp’s 2021 Integrated Resource Plan
(IRP), Volume I, Chapter 6 (Load and Resource Balance). The Company’s
responses to IPUC Data Request 29 are therefore only referencing Table 6.11 (Summer Peak – System Capacity Loads and Resources without Resource Additions) and Table 6.12 (Winter Peak System Capacity Loads and Resources without Resource Additions).
(a) Please refer to the 2021 IRP, Volume I, Table 6.10 (Existing DSM Resource
Summary) on page 147 for the programs included in the “Existing – Demand Response” line in both Table 6.11 and Table 6.12. (b) Energy Storage is not included in Table 6.11 (Summer Peak – System
Capacity Loads and Resources without Resource Additions) and Table 6.12 (Winter Peak – System Capacity Loads and Resources without Resource Additions) (emphasis added). (c) For an explanation of how the capacity values in Table 6.11 and Table 6.12
are determined, please refer to the 2021 IRP, Volume I, Chapter 6 (Load and
PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 29
Resource Balance), section “Capacity and Energy Balance Overview” on page 149. (d) PacifiCorp assumes the request is for the peak capacity for the interruptible
contracts included in the “Existing – Demand Response” line of Table 6.11
and Table 6.12. Based on the foregoing assumption, the Company responds as follows:
Please refer Please refer to Attachment IPUC 29 which reports the Summer
Peak megawatts (MW) and Winter Peak MW by year. Please refer to the Company’s response to subpart (c) above regarding how the peak values are determined. (e) PacifiCorp decided to list demand response (DR) as a reduction to load in the
2021 IRP because DR resources are dispatchable reductions to load and it was
therefore determined that it was more appropriate to include them in the total obligation group. The planning reserve calculation in the 2021 IRP thus accounts for all programs that reduce load in the same way.

Recordholder: Brian Osborn Sponsor: Shay LaBray

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 31
IPUC Data Request 31 2021 Integrated Resource Plan (IRP) Page 161 of the 2021 Integrated Resource Plan Volume I lists that, for energy
balance, Existing Resources= Thermal+ Hydro+ Renewable+ Firm Purchases+
QF - Sales; and Obligation= Load + Firm Sales. What is the difference between "Sales" and "Firm Sales"?
Response to IPUC Data Request 31
“Sales” are system balancing market sales. “Firm Sales” are wholesale firm sales contracts.
Recordholder: Dan Swan
Sponsor: Shay LaBray

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 32
IPUC Data Request 32 2021 Integrated Resource Plan (IRP) Page 222 of the 2021 Integrated Resource Plan Volume I states that, in
developing resource portfolios for the 2021 IRP, PacifiCorp included modeling to
endogenously select transmission options in consideration of relevant costs and benefits. Page 242 states that the base transmission topology shown in Figure 8.3 is used in each of the three PLEXOS models, and any transmission upgrades
selected by LT and ST model processes that provide incremental transfer
capability among bubbles in this topology are part of the portfolio. Please answer the following questions:
(a) Please explain whether Boardman-to-Hemingway, Gateway South, and Gateway West in the preferred portfolio are all selected by models or are assumed in the base transmission topology.
(b) What categories of transmission upgrades are selected by models? Response to IPUC Data Request 32 (a) In developing resource portfolios for the 2021 Integrated Resource Plan (IRP), PacifiCorp included PLEXOS modeling to endogenously select transmission
options, in consideration of relevant costs and benefits. These costs are
influenced by the type, timing, location, and amount of new resources, as well as any assumed resource retirements, as applicable, in any given portfolio. Energy Gateway South (and associated Segment D.1) and the Boardman-to-Hemmingway (B2H) projects were assumed in the initial cases as described in PacifiCorp’s 2021 IRP, Volume I, Chapter 8 (Modeling and Portfolio Evaluation Approach) and Chapter 9 (Modeling and Portfolio Selection Results) and were evaluated in the P02 Variant cases “P02b-No B2H”, “P02c-No GWS”, and “P02d-No RFP” and reported a benefit to customers by including the transmission projects. Please refer to the 2021 IRP, Chapter 8
(Modeling and Portfolio Evaluation Approach), Table 8.11 and the subsequent
narrative. (b) The transmission options in the PLEXOS model fall into three categories: 1. Incremental transmission options which increase transmission capacity
between topology bubbles, 2. Interconnection-only options which allow additional resource to be added to the system but do not include incremental transmission capacity, and

3. “Recovered” transmission, which is transmission capacity associated with existing resources that will retire within the study horizon. The
PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 32
transmission capacity is assumed to persist upon the retirement of the existing resource only if new resources are selected by the model to occupy the transmission capacity.

Recordholder: Dan Swan Sponsor: Shay LaBray

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 33
IPUC Data Request 33 2021 Integrated Resource Plan (IRP) Page 219 of Appendix K states that the hourly weighting factors are applied to the
capacity factors of fixed profile resources in the corresponding hours to determine
the weighted capacity contribution value in those hours. Page 218 lists the formula to calculate CV, which is the overall weighted capacity value of the resource. Please explain the purposes of weighted capacity contribution value in
specific hours and the overall CV, respectively. Response to IPUC Data Request 33 The intent of the capacity factor approximation method (CF Method) discussed in PacifiCorp’s 2021 Integrated Resource Plan (IRP), Volume II, Appendix K
(Capacity Contribution) is to identify how much a resource contributes to system
reliability in the hours with the greatest need. The first step is to prepare a large number of iterations of a single year (2030 was used in the 2021 IRP), with stochastic shocks to load, hydro, and thermal forced outages, and identify all of
the hours with a resource shortfall across all of the iterations. Some hours will
have no shortfalls, while some hours will have shortfalls across many iterations. The weighting treats every shortfall the same, and results in a higher weighting for those hours in which multiple shortfalls occurred. For example, if there were 100 shortfalls across all hours and iterations, an hour with shortfalls in 10 iterations would represent 10 percent (10/100) of the total capacity need, while an
hour with a shortfall in only one iteration would only represent 1 percent of the
total capacity need. A resource’s generation in the hour with 10 shortfalls would thus count 10 times as much toward the overall capacity value as the hour with only one shortfall.

If a resource has a 5 percent capacity factor (CF) in the hour with 10 shortfalls, it would receive a 0.5 percent capacity value for that hour (10 percent times 5 percent). If a resource has a 50 percent CF in the hour with one shortfall, it would also receive a 0.5 percent capacity value for that hour (1 percent times 50 percent). As a result, resources with similar contributions may be covering very
different periods across the study period.
Each megawatt (MW) of resource with a 5 percent CF in the hour with 10 shortfalls will reduce the risk of shortfalls and as more such resources are added, more of the risk will remain in other hours. Since there were a lot of shortfalls and the CF of the resource being added is low, it would take quite a few MWs to significantly reduce the risk in that hour. In contrast, each MW of resource with a 50 percent CF in the hour with one shortfall will also reduce the risk of shortfalls and as more such resources are
added, more of the risk will remain in other hours. Since there was only one
PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 33
shortfall to begin with, and the CF of the resource being added is high, a few MWs of that resource would significantly reduce the risk in that hour, at which point adding more of that resource would not provide a reliability benefit. As a result the CF Method is very sensitive to the portfolio being evaluated and the
results are not broadly applicable.
Improvements in portfolio reliability may require resources that span a range of loss of load conditions, so the capacity contribution alone does not necessarily
indicate which combination of resources achieve reliability.
Recordholder: Dan MacNeil Sponsor: Shay LaBray

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 34
IPUC Data Request 34 2021 Integrated Resource Plan (IRP) Page 221 of Appendix K states that the CF Method results are from a one-year
study period of 2030. Please explain why 2030 is selected and if the one-year
results are extrapolated to other years in the IRP planning horizon. Please explain how it was done.
Response to IPUC Data Request 34
The capacity factor approximation method (CF Method) results presented in PacifiCorp’s 2021 Integrated Resource Plan (IRP), Volume II, Appendix K (Capacity Contribution) provide an estimate of the contribution to reliability of individual resources. Portfolio changes over time would necessarily impact these
results, but 2030 captures some of the near-term changes that are expected to
occur over time given the preferred portfolio selections while leaving out less certain changes toward the end of the horizon.
The 2030 CF Method results have not been extrapolated to other years in the IRP
planning horizon. Recordholder: Dan MacNeil
Sponsor: Shay LaBray

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 35
IPUC Data Request 35 2021 Integrated Resource Plan (IRP) Page 129 of Appendix F states that the regulation reserve forecasting
methodology that results in 0.5 loss of load hours per year due to regulation
reserve shortage is appropriate for planning and ratemaking purposes, and that this is in addition to any loss of load resulting from transmission or distribution outages, resource adequacy, or other causes. Please explain why 0.5 loss of load
hours per year due to regulation reserve shortage is appropriate. Response to IPUC Data Request 35 The Company must maintain the balance of load and resources from moment to moment within a relatively small margin. If the Company’s portfolio of resources
is insufficient to serve load and maintain required operating reserves, it may be
required to cut firm load. In actual operations, the Company is required to maintain service to all customers in all hours. For planning purposes, the Company recognizes shortfalls in extreme circumstances could occur, for instance
when multiple forced outages coincide with low renewable output and high
summer temperatures. A target of one loss of load day in 10 years is common in the electric industry – this has been interpreted as 2.4 loss of load hours (LOLH) per year. The Company’s integrated resource planning focuses on loss of load due to resource adequacy, that is, the system-wide resource balance versus load and operating reserve requirement, which includes regulation reserves.

By assuming that load can be curtailed up to 0.5 hours per year, the quantity of regulation reserve needed to maintain compliance with applicable reliability standards is reduced. Allowing for some risk as a result of regulation reserve
needs while maintaining the total risk to customers within the industry target of
2.4 LOLH would necessarily mean maintaining a lower risk of loss of load due to high summer temperatures or high resource outages. The 0.5 hour per year target is intended to provide a reasonable balance between these risks. Note: the reliability standard underlying the regulation reserve requirement, North
American Electric Reliability Corporation (NERC) Standard BAL-001-2, requires
100 percent compliance in all periods, and curtailment of firm load represents a backstop for maintain reliable system operation. In actual operations, PacifiCorp may realize a lower loss of load probability (LOLP) because the regulation reserve requirement is a minimum, and, due to the granularity of PacifiCorp’s resources and market opportunities, larger amounts of reserves are likely to be available in any given hour. However, this condition cannot be counted upon in the hour-ahead setup of the balancing area (BA) in the event it is unavailable. Import opportunities from the energy imbalance market (EIM) would also reduce the likelihood that PacifiCorp would need to shed firm load for reliability reasons,
PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 35
however, the EIM is a non-firm energy market that is not able to be leaned on or counted upon for BA responsibilities.
Recordholder: Dan MacNeil
Sponsor: Shay LaBray

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 36
IPUC Data Request 36 2021 Integrated Resource Plan (IRP) What did the Company use as a reliability target, such as LOLE, LOLH, or
LOLP, to ensure the amount of resources are adequate to meet load across the
planning horizon? Then please explain how the Company ensured this reliability target was measured and met through the Company's modeling methodology and provide the resulting modeled reliability measurements across the 20-year
planning horizon for the top three portfolios.
Response to IPUC Data Request 36 The Company assumes that the term “top three portfolios” is intended to be a reference to the 2021 Integrated Resource Plan (IRP) preferred portfolio, with top
performing portfolios of interest being the 2021 IRP preferred portfolio, followed
by those portfolios eligible for the preferred portfolio and having the lowest present value revenue requirements (PVRR). Based on the foregoing assumption, the Company responds as follows:

The PLEXOS model has a loss of load probability (LOLP) -based functionality for portfolio selection in the long-term (LT) model. This functionality approximates the impact of stochastic variables on the load and resource balance and the resulting LOLP risk as part of resource selection. The resulting LT portfolios were not sufficiently reliable when evaluated over all hours in the short-
term (ST) model due to the LT model looking at 4-block per month of data.
Therefore, to meet the LOLP standard in the LT model (using the 13 percent capacity reserve margin and operating reserves as the primary reliability
requirements) reliability resource additions were required. The Company used the
hourly deterministic load and resource availability in the PLEXOS model as the basis for resource adequacy. Because the Company’s renewable resources play an increasing role in meeting reliability but did not vary stochastically in the Company 2021 IRP, the traditional LOLP-based analysis would not capture these effects. At the same time, regulation reserves held to cover uncertainty in
renewable output could also be used to reduce the risk of unserved energy related
to load or force outages on dispatchable generators in those periods when renewable output occurred less than expected. The Company’s approach to assessing reliability was described in the 2021 IRP
public input meeting held on June 25, 2021 / June 26, 2021, including an example of shortfalls and shortfall resolution, and is also described in the 2021 IRP, Volume I, Chapter 8 (Modeling and Portfolio Evaluation Approach).
PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 36
Please refer to Confidential Attachment IPUC 36 which provides assessments of shortfalls for the 2021 IRP preferred portfolio, and those portfolios eligible for the preferred portfolio and having the lowest PVRR.
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: Adam Kennedy Sponsor: Shay LaBray

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 37
IPUC Data Request 37 2021 Integrated Resource Plan (IRP) Please explain in detail how the Company verified that the final Portfolios meet
the reliability (LOLE, LOLH, or LOLP) target identified in the above target.
Response to IPUC Data Request 37
The Company assumes that the reference to “above target” is intended to be a
reference to IPUC Data Request 36. Based on the foregoing assumption, the Company responds as follows: Please refer to the Company’s response to IPUC Data Request 36.

Recordholder: Adam Kennedy Sponsor: Shay LaBray

PAC-E-21-19 / Rocky Mountain Power February 9, 2022 IPUC Data Request 38
IPUC Data Request 38 2021 Integrated Resource Plan (IRP) On page 242, the IRP states that "The CRM is a portfolio selection driver
adequate to the capabilities of the LT model. Consistent with past IRPs use of a
PRM, the CRM is not used once the initial portfolio is established. This is because ST reliability modifications to the portfolio rely on hourly resource availability and system requirements to directly determine reliability shortfalls and any
additional resource need at the hourly level". Please explain the logic used to
determine shortfalls and resource additions at an hourly level in the ST model and explain what is included for load obligation and resource capacity amounts when the ST model performs the hourly comparisons. Response to IPUC Data Request 38

The logic to determine the shortfalls for reliability is to measure the energy not served (ENS) and unserved reserves by running the preliminary long-term (LT) study through the short-term (ST) model. The ST model reveals any shortfalls on
an hourly basis by optimizing the dispatch of available resources to meet all
obligations and minimize costs. The ST model is therefore comparing all modeled resource capabilities to meet all modeled system requirements, which are inclusive of hourly load and operating reserves.
Recordholder: Dan Swan
Sponsor: Shay LaBray