20201202PAC to Staff 1-16.pdf

1407 W North Temple, Suite 330 Salt Lake City, Utah 84116
December 2, 2020 Jan Noriyuki Idaho Public Utilities Commission 472 W. Washington
Boise, ID 83702-5918 [e-mail] (C)
RE: ID PAC-E-20-14 IPUC 1st Set Data Request (1-16) Please find enclosed Rocky Mountain Power’s Responses to IPUC Data Requests 1-16. Provided on CD is Attachment IPUC 2-1. Provided on the Confidential CD are Confidential Attachments IPUC 2-2 and 4. 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 any subsequent 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
RECEIVED
2020December 2, PM 4:11
IDAHO PUBLIC
UTILITIES COMMISSION
PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 1
IPUC Data Request 1 Please provide an explanation and the mechanics for the derivation of the wind integration rate of $1.11 per MWh for wind powered QFs; and the solar integration rate of $0.85 per MWh for solar powered QFs.
(a) Please provide all inputs and assumptions used in these calculations. Please include the Excel spreadsheet with formulae intact and enabled.

(b) Please identify the key driver(s) for the difference in the increase in the wind integration rate (increase of $0.54/MWh; 95% increase) and the solar integration rate (increase of $0.25/MWh; 42% increase). Response to IPUC Data Request 1 (a) Please refer to PacifiCorp’s 2019 Integrated Resource Plan (IRP), specifically Volume II, Appendix F (Flexible Reserve Study) for details on the inputs to these assumptions. Please refer to the Company’s response to IPUC Data Request 2, specifically Attachment IPUC 2-1, file “App F - Flex Study PaR
results.xlsx” for the calculation of the wind and solar integration rates. The wind integration rate is shown in cell H80 of tab “Wind 2030”. The solar integration rate is shown in cell H80 of tab “Solar 2030”.

(b) Please refer to Figure F.15 in Appendix F (Flexible Reserve Study) of Volume II of the 2019 IRP. As shown in Figure F.15 integration costs used in the 2017 IRP were calculated for a 2017 test period and were escalated at inflation. For the 2019 IRP, integration costs were calculated over the life of the asset and a levelized value was applied in the portfolio development process. When
evaluating portfolio performance, the reserve requirements and reserve-
capable resources specific to the portfolio were included as part of the study, such that the integration cost is embedded within the results and no separate adjustment for integration is necessary.

Integration costs reflect the opportunity cost of holding incremental operating reserves. When more operating reserves are needed, a dispatchable generator may need to be held back and will not be able to generate to serve load or make wholesale sales. This can result in higher cost resources being called on to serve load or the loss of the margin between the generator’s variable cost
and the wholesale sales price. The Company’s generation surplus becomes
smaller over time as a result of unit retirements and load growth, particularly in 2028 and beyond. As this happens the cost of providing additional operating reserves increases as there are fewer and higher cost resources available to be called on to replace output that is held as reserves. This effect
is countered somewhat by increasing renewable energy supply, which drives down the marginal cost of supply when such resources are available, and by
PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 1
replacement dispatchable resources, such as gas plants or batteries, that can provide reserves at little or no cost in hours when they would not have been economic to dispatch.
PacifiCorp’s 2017 IRP and 2019 IRP is publicly available and can be accessed by
utilizing the following website link: https://www.pacificorp.com/energy/integrated-resource-plan.html

Recordholder: Dan MacNeil
Sponsor: To Be Determined

PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 2
IPUC Data Request 2 Please provide all work papers in Excel format with formulae intact and enabled that was used in the Flexible Reserve Study. Please also include the following:
(a) A detailed description of each work paper and how it was used in the study; and
(b) The SO and PaR portfolio/scenario files used in the study. A list of all the
assumptions and inputs included in each portfolio/scenario, and a summary of the parameters that were changed for each portfolio/scenario analysis performed. Response to IPUC Data Request 2

(a) The following work papers were provided in support of Appendix F - Flexible Reserve Study (“FSR”) of the 2019 Integrated Resource Plan (“IRP”), Volume II:

Please refer to Attachment IPUC 2-1: File “Annual Forecast with EIM.xlsx” - This file provides the hourly regulation reserve requirements for the 2017
historical study period, calculated based on actual forecasts and
deviations. The relationships between the forecasted load, wind, solar, and non-variable energy resources and overall actual error in the load and resource balance were used to determine the regulation reserve
requirements modeled in the 2019 IRP study period. For more details,
please refer to the Company’s response to IPUC Data Request 4. File “App F - Flex Study PaR results.xlsx” - This file provides the Planning and Risk (“PaR”) model results for the
various cases and the calculation of the wind and solar integration costs
reported in the FSR of the 2019 IRP, Volume II. File “App F Preferred Portfolio P45CNW Reserves inputs worksheet.xlsx”
- This file provides details on the reserve requirement inputs for the 2019 IRP preferred portfolio (case P45CNW). File “Tbl F.1,2,FigF.1,2 - Flex Resource 19IRP.xlsx”
PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 2
- This file provides supporting detail behind the Flexible Resource Needs Assessment, included on pages 110 through 114 of the FRS in the 2019 IRP, Volume II. This compares the requirements for operating reserves with the available supply.

Please refer to Confidential Attachment IPUC 2-2: File “Hourly Reserve Requirements Base_CONF.xlsx”
File “Hourly Reserve Requirements 500Wind_CONF.xlsx”
File “Hourly Reserve Requirements 500Solar_CONF.xlsx” - These files demonstrate the calculation of the hourly reserve requirement for three specific portfolios identified on pages 107 and108 of the FRS in the 2019 IRP, Volume II.

File “PaR Reserves Template Base - 2030_CONF.xlsx” File “PaR Reserves Template 500 Wind 2030_CONF.xlsx” File “PaR Reserves Template 500 Solar 2030_CONF.xlsx”

- To ease the inclusion of the reserve requirements in the PaR model, these three files have the hourly regulation requirements calculated in the “Hourly Reserve Requirements” files referenced above, but without the associated calculations.
(b) Please refer to Attachment IPUC 2-1 and Confidential Attachment IPUC 2-2
which provides the work papers that accompanied PacifiCorp’s 2019 IRP. The flexible reserves studies are described in the 2019 IRP, Volume II, Appendix F, starting on page 77.

PacifiCorp’s 2019 IRP is publicly available at the following link: https://www.pacificorp.com/energy/integrated-resource-plan.html
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 any subsequent Non-Disclosure Agreement (NDA) executed in this proceeding.

Recordholder: Dan MacNeil
Sponsor: To Be Determined
PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 3
IPUC Data Request 3 The Flexible Reserve Study discusses the Regulation Reserve Cost on pages 107-108. Please respond to the following:
(a) For the Wind Reserve Case, what year(s) was the 500 MW of proxy wind resources added to the portfolio and why this is appropriate;
(b) For the Wind Reserve Case, describe how the 5 locations where chosen and
why this is appropriate; (c) For the Wind Reserve Case, provide the proxy wind resource input assumptions (i.e., capacity factor, capacity factor at peak, etc.) used at each location and why this is appropriate;

(d) For the Wind Reserve Case, please explain why the case was evaluated for the study period 2030, how the year 2030 was chosen, and why this is appropriate;

(e) For the Solar Reserve Case, what year(s) were the 500 MW of proxy solar resources added to the portfolio and why this is appropriate; (f) For the Solar Reserve Case, describe how the 3 locations were chosen and why this is appropriate;

(g) For the Solar Reserve Case, provide the proxy solar resource input assumptions (i.e., capacity factor, capacity factor at peak, etc.) used at each location and why this is appropriate; and

(h) For the Solar Reserve Case, please explain why the case was evaluated for the study period 2030, how the year 2030 was chosen, and why this is appropriate. Response to IPUC Data Request 3

(a) The “Wind Reserve Case” was based on a 2030 study year. Because of retirements and resource additions, regulation reserve requirements and capability are expected to change significantly in the next few years. 2030 represents a reasonable snapshot of the conditions that are likely to be
prevalent in the future. 2030 was also used to determine planning reserve margins (“PRM”) and capacity contribution for the same reasons. Details on the portfolio used to determine PRM are provided in Appendix I - Planning Reserve Margin Study, of Volume II of the 2019 Integrated Resource Plan (“IRP”).

PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 3
(b) The five locations chosen are consistent with proxy wind resources available for inclusion in the preferred portfolio and included in the supply-side resource table (Table 6.1 and Table 6.2, of PacifiCorp’s 2019 IRP, Volume I, Chapter 6 - Resource Options).

(c) Details on the proxy wind resources were provided in the 2019 IRP, Volume II, Appendix P - Renewable Resources Assessment.
(d) Please refer to the Company’s response to subpart (a) above.
(e) The “Solar Reserve Case” was based on a 2030 study year. Please refer to the Company’s response to subpart (a) above. (f) The three locations chosen reflect a reasonable distribution of solar resource
additions, with half on the east in Utah South, and half in the west, split
between Southern Oregon and Yakima. These locations for solar resources were identified in the 2017 IRP Update preferred portfolio, as shown in Table 8.4.

(g) Details on the proxy solar resources were provided in the 2019 IRP, Volume II, Appendix P - Renewable Resources Assessment. (h) Please refer to the Company’s response to subpart (a) and (e) above.
PacifiCorp’s 2017 IRP and 2019 IRP is publicly available at the following link:
https://www.pacificorp.com/energy/integrated-resource-plan.html

Recordholder: Dan MacNeil Sponsor: To Be Determined

PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 4
IPUC Data Request 4 If not provided in response to Request No. 2, please provide the data used to estimate the quantile regression model referenced on page 4, line 3 of the Application and on page 93 of the Flexible Reserve Study. Please provide in
Microsoft Excel with formulae intact and enabled. In addition, please provide the following:
(a) Please provide copies of the quantile regression results for model(s) the
Company estimated for its Flexible Reserve Study and identify the Company’s preferred model if more than one model was estimated. Results should include statistics and diagnostics applicable to quantile regression and coefficient estimates with associated standard errors, t-statistics, p-values, and confidence intervals;

(b) Please explain how regulation reserve requirements are co-optimized in the quantile regression model; and
(c) Please provide descriptions of all variables used in the regression modeling.
Response to IPUC Data Request 4 (a) Please refer to Confidential Attachment IPUC 4. Only one model was estimated per balancing authority area (“BAA”), so there is no preferred
model. PacifiCorp did not analyze standard errors as part of the flexible
reserve study. The model used in these quantile regressions arises from a situation in which the relationships between the independent variables (“forecasts”) and dependent variables (“forecast error”) are decided before the
fact in accordance with the concepts which drive regulation reserves. For
example, in Figure F.3, on page 94 of Appendix F - Flexible Reserve Study in PacifiCorp’s 2019 Integrated Resource Plan (“IRP”), Volume II a third degree polynomial was determined to be the best representation of the relationship between forecasts and forecast error when excluding outliers. Since these relationships (“the fit”) among variables were determined as appropriate
before modeling began, there was no need for PacifiCorp to examine
goodness of fit statistics which seek to provide a justification for the selection of one model over another. Furthermore, unlike statistical analyses in which the relationships are unknown before the fact and the data represent a sample drawn from an unknown population, in this case, not only are the relationships
known and defined before the fact but the data represents the population and not a random sample. (b) For each BAA, a single regression incorporates all inputs to provide one formula which returns the regulation reserve requirements, before adjustment
for additional diversity associated with the energy imbalance market. This is
PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 4
as opposed to having separate regressions for different customer classes and then sequentially performing additional portfolio diversity benefit calculations to derive the regulation reserve requirement. In this sense the regulation reserves can be considered “co-optimized” as opposed to sequentially
calculated.
(c) There are four independent variables used in the regression modeling:
1. Hour-ahead load forecast, as a percentage of peak load.
2. Hour-ahead wind forecast, as a percentage of wind nameplate capacity.
3. Hour-ahead solar forecast, as a percentage of solar nameplate capacity.
4. Hour-ahead non-variable energy resources (“VER”) forecast, as a percentage of the maximum schedule for each non-VER. The independent variables represent information available prior to the hour that can be used to predict the potential need for regulation reserves to maintain the load and resource balance in the event that load net of wind, solar
and non-VERs is higher than forecasted. These regulation reserves can be held available and deployed within the hour when necessary. The error in load net of wind, solar and non-VERs is represented by “Combined.Diversity.Error” which is the dependent variable in the regression. This is the historical
forecast error for the portfolio as a whole, which is the sum of the errors for load, wind, solar, and non-VERs. PacifiCorp’s 2019 IRP is publicly available at the following link:
https://www.pacificorp.com/energy/integrated-resource-plan.html
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 any subsequent Non-Disclosure Agreement (NDA) executed in this proceeding. Recordholder: Dan MacNeil

Sponsor: To Be Determined
PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 5
IPUC Data Request 5 Paragraph 14 of the Application states that inter-hour system balancing integration cost was not included in the 2019 IRP “based on the minimal impact of the calculated cost in the study and possible interaction with EIM.” Please
explain how inter-hour system balancing integration cost was determined in the 2017 Flexible Reserve Study. In the explanation, please include the following:
(a) What is the significance of gas plants “dispatched in the EIM to meet regional
demand, not just the PacifiCorp demand reflected in the PaR model”; and (b) Why did the Company use “sub-optimal gas plant commitment based on day-ahead load, wind, and solar forecasts, rather than actuals”?
Response to IPUC Data Request 5
(a) The PacifiCorp’s Planning and Risk (“PaR”) model used in its 2017 Integrated Resource Plan (“IRP”) and 2019 IRP only included PacifiCorp
loads and resources, and limited connections to other entities via system
balancing purchases and sales at market points. The inter-hour system balancing cost represented the cost of imperfectly committing gas units based on forecasted conditions in the day-ahead time frame, relative to a perfect commitment based on actual hourly generation levels. Because combined cycle gas plants have minimum-up and minimum-down times of six hours or
more, and gas must be nominated the day before, there is limited ability to
change the gas output if conditions differ from expectations. For example, if wind output was expected to be low, gas plants might be committed online, but if wind output unexpectedly increased, those gas plants might no longer be
economic, as transmission congestion could prevent the sum of the wind and
gas generation from reaching load or markets. Sub-optimal outcomes can also occur if gas plants are left offline, if renewable output is lower than expected. The energy imbalance market (“EIM”) provides an alternative source or sink, such that rather than being dependent largely on PacifiCorp’s resources as reflected in the 2017 IRP version of inter-hour system balancing, the clearing
price in EIM reflects a broader range of conditions and resource options
across many balancing authority areas . The increase in the depth of the supply stack means that a given change in the net load position is likely to have a smaller impact on marginal costs in EIM, relative to what PacifiCorp’s more limited supply stack would require for that same size change. Put
another way, PacifiCorp’s day-ahead wind forecast error may be big for PacifiCorp to handle, but relatively small for the EIM footprint as a whole such that the cost of sub-optimal commitment is reduced. (b) The PaR model automatically identifies optimized gas plant commitment
based on the modeled load and renewable resource inputs. In essence this
PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 5
reflects perfect foresight of the conditions that will prevailing during gas plant operation. In reality, gas plant commitment for combined cycle gas plants is largely locked in on a day-ahead basis, when forecasted conditions are still uncertain. By modeling “sub-optimal” gas plant commitment, PacifiCorp was
just trying to emulate achievable levels of accuracy and optimization
consistent with actual operations that do not have perfect foresight. PacifiCorp’s 2017 IRP and 2019 IRP is publicly available at the following link:

https://www.pacificorp.com/energy/integrated-resource-plan.html Recordholder: Dan MacNeil Sponsor: To Be Determined

PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 6
IPUC Data Request 6 Please provide the inter-hour integration cost impacts for the 2019 IRP. If the cost impacts are not available, please provide an estimated amount and describe the method used to determine the estimate.
Response to IPUC Data Request 6
PacifiCorp did not prepare inter-hour integration cost estimates for the 2019
Integrated Resource Plan (“IRP”). The most recent inter-hour integration cost estimate for wind and solar is approximately $0.14 per megawatt-hour ($/MWh), from Appendix F - Flexible Reserve Study in PacifiCorp’s 2017 IRP, Volume II. For a summary of the methodology, please refer to the Company’s response to IPUC Data Request 5. For more details, please refer to Appendix F in
PacifiCorp’s 2017 IRP.
PacifiCorp’s 2017 IRP and 2019 IRP is publicly available and can be accessed by utilizing the following website link:

https://www.pacificorp.com/energy/integrated-resource-plan.html

Recordholder: Dan MacNeil
Sponsor: To Be Determined
PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 7
IPUC Data Request 7 Please explain why possible interaction with EIM is a rationale for not including inter-hour integration costs? Response to IPUC Data Request 7 Please refer to the Company’s response to IPUC Data Request 5.

Recordholder: Dan MacNeil
Sponsor: To Be Determined

PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 8
IPUC Data Request 8 Page 101 of the 2019 Flexible Reserve Study states that while substantial EIM imports do occur in some hours, it is only appropriate to rely on PacifiCorp’s diversity benefit associated with EIM participation as these are derived from the
structure of the EIM rather than resources contributed by other participants. Please define “diversity benefit associated with EIM participation” and “resources contributed by the other participants” and explain the difference between the two.
Response to IPUC Data Request 8 The difference between the sum of the individual requirements and the requirement for the EIM footprint as a whole is the “diversity benefit associated with EIM participation.” As part of the energy imbalance market (“EIM”)
process, the California Independent System Operator (“CAISO”) requires
participating utilities to make available sufficient flexible resources to respond to changes over short-time intervals. CAISO calculates a flexible requirement for each balancing authority area (“BAA”), as well as for the EIM footprint as a
whole. The requirement is smaller for the EIM footprint as a whole because in
any interval some BAAs are likely to have conditions that are offsetting those of the rest of the footprint, or which are less than their individual requirement. The amount required of each BAA is reduced by this diversity in proportion with their individual obligation, such that the total flexible requirement is equal to the target for the EIM footprint.

Technically, the diversity benefit reflects “resources contributed by other participants.” Each BAA is counting on other BAAs to provide additional resources when needed, and the CAISO’s analysis indicates the combined total is
typically sufficient. Along with this benefit comes the reciprocal the obligation to
dispatch resources to meet imbalance needs in other BAAs, as part of the EIM process. The required amounts are intended to help ensure the EIM operates smoothly, and do not ensure that volumes provided will be sufficient to maintain reliability
throughout the EIM footprint. BAAs that participate in EIM remain independently
responsible for compliance with their reliability obligations. As a result, while resources contributed by other participants might be available to help cover PacifiCorp’s resource shortfalls in amounts that exceed the diversity benefit calculated by the CAISO, they cannot be relied upon to be available. Therefore
the only credit to PacifiCorp’s regulation reserve requirements is the diversity benefit calculated by CAISO. The remaining capacity necessary to maintain reliable operation must be provided by PacifiCorp.

PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 8
Recordholder: Dan MacNeil
Sponsor: To Be Determined

PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 9
IPUC Data Request 9 Please provide a description of each portfolio in each case listed in Table F.10 on page 107 of the Flexible Reserve Study. Please describe each portfolio, how it was determined, its source (example: 2019 IRP preferred portfolio), and why the
portfolio was appropriate for each case. Response to IPUC Data Request 9
2015 Actuals + Projected Solar – This portfolio represents regulation reserve requirements for the following within PacifiCorp’s balancing authority areas (BAA): - actual 2015 load
- actual 2015 wind
- actual 2015 non-variable energy resources, and - projected solar resources consistent with signed contracts
A negligible quantity of utility-scale solar resources were online during 2015, but
a large quantity of solar resources had been contracted but were not yet operational. To better reflect expected future operations, a projection of the effects of solar uncertainty and associated requirements was used in the analysis. Note that some resources and load in PacifiCorp’s BAAs are wholesale transmission customers that receive regulation service consistent with
PacifiCorp’s Open Access Transmission Tariff (OATT) Schedule 3 or Schedule
3A. The actual data associated with these customers is incorporated in the reported results.
2017 Actuals - This portfolio represents the regulation reserve requirements for
2017 actual load, wind, solar, and non-variable energy resources (VER) in PacifiCorp’s BAAs. Actual data for the load and resources of wholesale transmission customers are included in the reported results. 2030 Portfolio - The base case portfolio is the same as that used to set the
planning reserve margin (PRM) for the 2019 Integrated Resource Plan (IRP), as
discussed in Appendix I (Planning Reserve Margin Study). This case incorporates assumptions consistent with the 2017 IRP Update, updated to reflect current inputs as of August 2018 and without any wind or solar resources additions beyond those that had already been committed at that time. This portfolio also
does not include the requirements associated with the load or resources for wholesale transmission customers. 2030 Portfolio + 500 MW Wind / 2030 Portfolio + 500 MW Solar - These portfolios are based on the 2030 Portfolio described above. For more details on
PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 9
the incremental wind and solar, please refer to the Company’s response to IPUC Data Request 3. PacifiCorp’s 2019 IRP and 2017 IRP are publicly available at the following link:

https://www.pacificorp.com/energy/integrated-resource-plan.html
Recordholder: Dan MacNeil
Sponsor: To Be Determined

PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 10
IPUC Data Request 10 Please explain the purpose of the 50 MW Reserve Case on Page 108, how the escalation of wind and solar results was conducted, and why an additional 50 MW reserve requirement was included in every hour from 2018 through 2036.
Response to IPUC Data Request 10
The “50 MW Reserve Case” represents a benchmark of the cost of operating
reserves over time. Due to the granularity of the data, the wind and solar reserve cases both were prepared for a single year, 2030. Including a flat increment of reserves in all hours was easier to model and allowed a single long-term study to inform the results for both wind and solar. The integration cost is applied to wind and solar resources as part of portfolio selection in the System Optimizer model
(SO model) because it does not account for operating reserve requirements and
would not otherwise recognize these additional costs. An analogous situation is also true for resources which provide operating reserves, as this capability is not valued in SO model and would be unaccounted for absent the inclusion of a
credit. Therefore the “50 MW Reserve Case” was also used to calculate the
operating reserve credits applied to storage, gas peaking plants, and interruptible load resource options. The cost of operating reserves in the “50 MW Reserve Case” in each year was divided by the cost in 2030, and the resulting annual stream was used to escalate
both the wind and solar values from 2030 to the end of the study period and from
2030 back to the start of the study. Please refer to the Company’s response to IPUC Data Request 2, specifically Attachment IPUC 2-1, file “App F – Flex Study PaR results.xlsx”, tab “50 MW Reserve”, row 77 for the escalation based
on the “50 MW Reserve Case”.

Recordholder: Dan MacNeil
Sponsor: To Be Determined

PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 11
IPUC Data Request 11 Page 102 of the 2019 Flexible Reserve Study states that the Company has applied the historical distribution of EIM diversity benefits from March 2018 through the beginning of this study in July 2018, and relatively small incremental EIM
diversity benefits are expected going forward as additional entities participate in the EIM, but operational data on new participants were not available at the time the study was prepared. Does the study assume EIM diversity benefits are
constant throughout the study period? If so, what are the assumed values? If not,
how do they vary? Response to IPUC Data Request 11 The 2019 Flexible Reserve Study assumes EIM diversity benefits are constant.
For the assumed values, please refer to the Company’s response to IPUC Data
Request 2, specifically Confidential Attachment IPUC 2-2, file “Hourly Reserve Requirements Base_CONF.xlsx”, tab “EIM”, cells I4 and I5 for assumed values for PacifiCorp East balancing authority area (“BAA”) and PacifiCorp West BAA,
respectively.

Recordholder: Dan MacNeil
Sponsor: To Be Determined
PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 12
IPUC Data Request 12 Page 1 of the Application states that the integration charges will be applied against published avoided cost rates except in those circumstances where the QF developer specifies in the PPA to deliver the QF output to Rocky Mountain Power
on a firm hourly schedule. Please explain how the Company plans to hold a QF accountable for “a firm hourly schedule”.
Response to IPUC Data Request 12
A qualifying facility (“QF”) which is located within another balancing authority area (“BAA”) and chooses to wheel is generation to the Company would be subject to charges for ancillary services from its source BAA that would include the Company’s integration cost. For an off-system QF, the Company would
receive firm output at an intertie with the source BAA consistent with the QF’s
transmission schedules. Absent being off-system, standard wind and solar QFs that would be subject to integration charges would not be able to provide a firm hourly schedule and avoid the integration charge.

Recordholder: Dan MacNeil
Sponsor: To Be Determined
PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 13
IPUC Data Request 13 The Application proposes one charge for wind and one charge for solar in 2018 dollars to be used in the SAR model throughout the life of a QF contract. Please explain why the Company does not consider inflation in the cost of integrating
wind and solar over a 20-year contract term. Response to IPUC Data Request 13

The existing integration cost is a single value that is not incorporated within the reported rate but instead subject to a further adjustment. The Company uses a constant rate only for contracts for wind and solar resources up to 100 kilowatts (“kW”) that are eligible for published rates in the Company’s filing and does so for simplicity in administering these contracts. The Company would consider a
different representation of the integration cost within the Surrogate Avoided
Resource (“SAR”) model. To the extent the Commission prefers an annual representation of integration costs for determining avoided costs, the Company recommends using the annual values reported in Appendix F - Flexible Reserve
Study, Figure F.15 in the 2019 Integrated Resource Plan (“IRP”), Volume II,
rather than escalating at inflation. For the calculations supporting the values in Figure F.15, please refer to the Company’s response to IPUC Data Request 2, specifically Attachment IPUC 2-1, file “App F - Flex Study PaR results.xlsx”, row 78, in tab “Wind 2030” and tab “Solar 2030”.
PacifiCorp’s 2019 IRP is publicly available at the following link:
https://www.pacificorp.com/energy/integrated-resource-plan.html
Recordholder: Dan MacNeil
Sponsor: To Be Determined
PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 14
IPUC Data Request 14 Please explain why the Company does not consider different penetration levels of wind and solar to determine integration charges in PURPA contract rates. Response to IPUC Data Request 14 The Company has a large system which already has a significant penetration of
wind and solar resources in a diverse set of locations. As shown in Table F.10 in
the Flexible Reserve Study of the 2019 Integrated Resource Plan, the integration cost assumptions were from a 2030 baseline of over 3,000 megawatts (MW) of wind resources, and over 2,000 MW of solar resources. The expected penetration of wind and solar resources qualifying for published rates would not have a significant impact on these totals.

The Company’s 2019 IRP evaluated portfolio performance in the Planning and Risk (PaR) model based on the inclusion of portfolio-specific integration requirements (regulation reserves), and the attributes of the resources within a
portfolio that can provide regulation reserves, resulting in an integration cost that
is portfolio specific and embedded within the overall results. For non-standard qualifying facilities seeking prices under the IRP Methodology, the Company would use same method. PacifiCorp’s 2019 IRP is publicly available at the following link:

https://www.pacificorp.com/energy/integrated-resource-plan.html
Recordholder: Dan MacNeil
Sponsor: To Be Determined
PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 15
IPUC Data Request 15 If the cost of integrating PURPA wind and solar increases due to inflation and increasing levels of solar and wind penetration, please provide rate schedules out to year 2045 to account for inflation and to account for different penetration
levels. Please provide work papers with formula intact in the Company’s derivation.
Response to IPUC Data Request 15
The Company has calculated integration costs over time that account for changes in the composition of its system, rather than escalating at inflation. The annual values were reported in Appendix F - Flexible Reserve Study, Figure F.15 in the 2019 Integrated Resource Plan (“IRP”), Volume II. For the calculations
supporting the values in Figure F.15, please refer to the Company’s response to
IPUC Data Request 2, specifically Attachment IPUC 2-1, file “App F - Flex Study PaR results.xlsx”, row 78, in tab “Wind 2030” and tab “Solar 2030”. The Company has not calculated integration costs at other levels of solar and wind
penetration for use with published avoided cost rates.
PacifiCorp’s 2019 IRP is publicly available at the following link: https://www.pacificorp.com/energy/integrated-resource-plan.html

Recordholder: Dan MacNeil
Sponsor: To Be Determined
PAC-E-20-14 / Rocky Mountain Power December 2, 2020 IPUC Data Request 16
IPUC Data Request 16 The Application states that the integration charges will be applied to wind and solar under published avoided cost rates. Does the Company plan to apply these integration charges for determining PURPA rates in the Integrated Resource
Planning (IRP) method? Please explain. Response to IPUC Data Request 16

No. In its 2019 Integrated Resource Plan (“IRP”), the Company evaluated portfolio performance within the Planning and Risk model based on the inclusion of portfolio-specific integration requirements (regulation reserves), and the attributes of the resources within a portfolio that can provide regulation reserves, resulting in an integration cost that is portfolio specific and embedded within the
overall results. For non-standard qualifying facilities seeking prices under the IRP
Methodology, the same method would be employed. PacifiCorp’s 2019 IRP is publicly available at the following link:

https://www.pacificorp.com/energy/integrated-resource-plan.html Recordholder: Dan MacNeil
Sponsor: To Be Determined