20230203PAC to Staff 34-53.pdf

1407 W North Temple, Suite 330 Salt Lake City, Utah 84116
February 3, 2023 Jan Noriyuki Idaho Public Utilities Commission 472 W. Washington
Boise, ID 83702-5918 [e-mail] (C) RE: ID PAC-E-22-13
IPUC Set 3 (34-53) Please find enclosed Rocky Mountain Power’s Responses to IPUC 3rd Set Data Requests 34-53. The Confidential Attachments IPUC 36, 40, and 49 are provided via BOX. 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. If you have any questions, please feel free to call me at [phone]. Sincerely, ____/s/____ Mark Alder
Manager, Regulation
Enclosures C.c.: Thomas J. Budge/Bayer [e-mail] (C) Eric L. Olsen/IIPA [e-mail] Lance Kaufman/IIPA [e-mail] Brian C. Collins/Bayer [e-mail] (C)
Greg Meyer/Bayer [e-mail] (C)

RECEIVED
2023 February 3, 11:35AM
IDAHO PUBLIC
UTILITIES COMMISSION
PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 34
IPUC Data Request 34 For the Commercial and Industrial (C&I) Demand Response (DR) program, please describe the Company’s intended practices regarding the use of the
Integrated Resource Plan (IRP) avoided cost data to evaluate the cost-
effectiveness of its programs for a given year and for program planning for the next year (i.e., use the avoided cost available at program planning for evaluating the cost-effectiveness for that given year, use the most current avoided cost at
time of evaluation, etc.).
Response to IPUC Data Request 34 The Company intends to follow the same practices regarding the use of PacifiCorp’s integrated resource plan (IRP) avoided cost data that are
used for energy efficiency (EE), which is to use the most current avoided
cost data for cost effectiveness valuation. However, for annual reporting, the Company will use the same vintage of avoided costs that were used at the time of program planning. The purpose of the annual reports is to
reflect how the Company fared against its planning and targets, thus
using the same assumptions and avoided costs for planning and reporting is appropriate. Recordholder: Peter Schaffer

Sponsor: Peter Schaffer

PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 35
IPUC Data Request 35 In response to Production Request No. 7, the Company states the megawatt amounts committed for participation in the C&I DR program provides value as a
contingency reserve even when events are not actively being called. In review of
the Company’s response to Production Request No. 26, Staff notes the value provided to non-event hours is attributed to “5 Regulation Reserve” which on average during the year is significantly higher than either spin or non-spin
contingent reserves. With respect to the valuation differences, please address the
following: (a) Please fully explain the differences (i.e. benefits and/or constraints) between contingent spin and non-spin reserves compared to regulation reserves.
(b) In actual system operation how are contingent spin and non-spin reserves
dispatched compared to regulation reserves. (c) Please fully explain the Company’s justification for valuing the C&I DR
program during non-event hours using regulation reserves. Response to IPUC Data Request 35 (a) For details on the different types of reserves, please refer to PacifiCorp’s 2021 Integrated Resource Plan (IRP), specifically Volume II, Appendix F (Flexible
Reserve Study). PacifiCorp’s 2021 IRP is publicly available and can be
accessed by utilizing the following website link: Integrated Resource Plan (pacificorp.com)

Note: referencing the Company’s response to IPUC Data Request 26, the spin/non-spin reserve values within Confidential Attachment IPUC 26 have been reduced to 3 percent of the stated value based on the calculation in row 5 of tab “Calc”. The Company must hold contingency reserves equal to 3 percent of its load and 3 percent of its generation. To the extent that
generation is used to serve load, an increment of load thus requires 6 percent
contingency reserves, with half spinning and half non-spinning. By reducing load during curtailment events, the proposed program not only provides energy benefits, it also reduces the Company’s contingency reserve obligations by a proportionate amount. This is true of any load reduction,
including energy efficiency (EE) measures, and is not related to the dispatch or reserve-holding characteristics of the proposed demand response (DR) program. (b) In actual operations, spin and non-spin reserves are deployed only
immediately after a qualifying contingency event, e.g. an unexpected
PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 35
generator or transmission outage. The reserve resources must deploy their reserve capability within 10 minutes, but within 60 minutes, the Company must deploy other replacement resources and restore its spin and non-spin reserve capability, so that it can be deployed in response to future contingency
events. Because these are relatively uncommon, they tend not to overlap,
though it can and does occur. The Company also participates in reserve sharing programs and at times deploys or receives contingency reserves from other utilities

Regulation reserves are deployed to maintain the load and resource balance in response to any other cause other than qualifying contingency events. Generally, this is the result of variation in load, wind, solar, or other generation. As discussed in PacifiCorp’s 2021 IRP, Volume II, Appendix F, the Company must continuously maintain the load and resource balance, but
the relevant reliability standards allow some flexibility over time. The
Company must meet a certain level of performance for one-minute intervals viewed in aggregate and must also ensure that major deviations are brought within specified bounds within 30 minutes. As a result, there is no fixed
duration for regulation reserve deployment and successive deployments due to
changing load, wind, solar and other generation conditions are possible. The magnitude of these changes varies widely – small regulation reserve deployments occur continuously, while the need for very large deployments is much less frequent. Because it is difficult to predict when large deployments may be needed, a significant portion of the regulation reserve supply may be
deployed relatively infrequently. In addition, as part of the Company’s
participation in energy imbalance market (EIM), most of its regulation reserve resources are made available to the market for economic dispatch. While resources are still deployed to address variations in load, wind, solar, and
other generation, those variations may be on another EIM participant’s
system, rather than the Company’s. Or lower-cost transfers from another utility’s resources may be used to maintain PacifiCorp’s load and resource, rather than resources in PacifiCorp’s balancing authority areas (BAA). (c) The regulation reserve price represents the opportunity cost of holding back
the associated dispatchable resources. When additional regulation reserve
resources like DR are made available, relatively low-cost generators are released from holding reserves and can generate to serve load, reducing the need for more expensive sources of supply, or can support wholesales which reduces revenue requirement. The net benefit from either of these outcomes is reflected in the regulation reserve price. Specific to the proposed DR program, by holding more of the “East 5 Regulation” product for the PacifiCorp East (PACE) BAA, other resources in the east BAA are relieved of that obligation and can be deployed in more beneficial uses.

PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 35
Recordholder: Dan MacNeil Sponsor: Dan MacNeil

PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 36
IPUC Data Request 36 Please recalculate the C&I DR program’s avoided cost provided in response to Production Request No. 26 using the hourly contingent spin reserve amounts
instead of the hourly regulation reserve amounts and show the difference. Further,
please provide justification for using the higher amount. Confidential Response to IPUC Data Request 36

Please refer to Confidential Attachment IPUC 36 which provides the sensitivity analysis which generates an avoided cost value. This value is based on changes made to using hourly spin reserve amounts instead of hourly regulation reserve amounts. As defined in the Company’s response IPUC Data Request 35, the program can have regulation reserve values attributed to it and therefore dispatch
assumptions used in the avoided cost modeling relied on higher value regulation
reserves as the program aims to maximize value in operations and dispatch. 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. Recordholder: Peter Schaffer
Sponsor: Peter Schaffer

PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 37
IPUC Data Request 37 Please explain the PLEXOS Preferred Portfolio baseline forecast model data and how it is used to determine the C&I DR program avoided cost in response to
Production Request No. 26.
Response to IPUC Data Request 37
PLEXOS is an optimization modeling tool that informs the Company’s integrated
resource plan (IRP). It takes load and resource inputs and models how to dispatch a portfolio of resources to meet future system demand in a least cost, least risk manner in compliance with state policies. The Company uses PLEXOS model outputs, such as the hourly locational
marginal prices (LMP), regulation reserve costs and contingency reserve costs to
inform the benefits or avoided costs that demand response (DR) can produce in any given hour.

Recordholder: Peter Schaffer / Dan MacNeil Sponsor: Peter Schaffer / Dan MacNeil

PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 38
IPUC Data Request 38 Please explain the Company’s approach for considering the C&I DR program benefit in the baseline forecast model specific to Idaho versus:

(1) the PACE Balancing Authority Area, and (2) the total PacifiCorp system.
Response to IPUC Data Request 38 The Company’s PLEXOS model optimizes all resource options (including both supply resources and demand-side) on a system basis. All resources are optimized against all of the needs across PacifiCorp’s system. Those needs include loads in a
variety of locations, market purchase and sale opportunities, and reserve
obligations held within the PacifiCorp East (PACE) or PacifiCorp West (PACW) balancing authority areas (BAA).
The proposed demand response (DR) program provides energy (via load
reductions) in Idaho and provides operating reserves to PACE. It thus avoids the need for energy deliveries to Idaho from other locations and reduces the need for operating reserves from other PACE resources. The energy and/or operating reserves that are freed up may in turn avoid higher cost sources of supply elsewhere on the Company’s system.

While the PLEXOS model does not identify benefits specifically related to the Idaho jurisdiction, high loads in Idaho would tend to increase the value of resources (or load reductions) in Idaho, therefore, deployment under those
conditions would be reasonable. However, to the extent system resources such as
solar are plentiful during summer afternoons, the model will wait to deploy DR resources until periods with the highest value, generally during summer evenings. Recordholder: Dan MacNeil

Sponsor: Dan MacNeil
PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 39
IPUC Data Request 39 Please explain how the baseline model data provided in response to Production Request No. 26 includes the proposed C&I DR program specific to Idaho.
Response to IPUC Data Request 39 Referencing the Company’s response to IPUC Data Request 26, specifically
Confidential Attachment IPUC 26, the shadow price (i.e. locational marginal
price (LMP) or marginal energy value) and operating reserve prices in columns I through L of tab “Calc” are drawn from the results of the PacifiCorp’s 2021 Integrated Resource Plan (IRP) preferred portfolio. Such prices are dependent on the portfolio of resources they are drawn from – a portfolio with lots of solar generation will have lower marginal prices during the day, while adding storage
to that portfolio will increase marginal prices during the day, but reduce them in
the highest cost hours in the evening. The 2021 IRP preferred portfolio included the proposed Idaho commercial and
industrial demand response (DR) program and the marginal prices are
representative of the impact of not having that program in the portfolio, since it is relatively small. For large resources changes, congestion and the elasticity of the supply curve would impact the marginal price as more and more resources are added or removed.

Recordholder: Dan MacNeil Sponsor: Dan MacNeil

PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 40
IPUC Data Request 40 In reference to the work papers provided in Response to Production Request No. 26, please provide the basis, supporting calculations, and an explanation of how the
Company isolated the Transmission & Distribution (T&D) avoided costs specific to
Idaho. Response to IPUC Data Request 40

Transmission and distribution (T&D) avoided costs are calculated based on prospective capital projects or upgrades associated with increased load. T&D avoided capacity costs represent the potential cost impacts on utility T&D investments from changes in peak loadings on the utility systems. Reductions in peak loadings via customer demand reductions can reduce the need for some transmission projects and allow for deferral or
avoidance of those projects. The T&D costs are derived from the Company’s 2021
Integrated Resource Plan (IRP), specifically as described in Volume I, Chapter 7 (Resource Options), Table 7.10 (State-specific Transmission and Distribution Credits) on 211. Transmission is calculated on a system-wide basis pursuant to how the Multi-State
Inter-Jurisdictional Cost Allocation Protocol (currently the 2020 Protocol) assigns
transmission costs across all states, and assigns distribution costs based on Idaho specific capital projects. The Company’s 2021 IRP is publicly available and can be accessed by utilizing the following website link:

Integrated Resource Plan (pacificorp.com) Please refer to Confidential Attachment IPUC 40, which provides a copy of the
supporting work paper for Table 7.10 (State-specific Transmission and Distribution
Credits) as provided on the confidential data disk that accompanied PacifiCorp’s 2021 IRP. 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.
Recordholder: Peter Schaffer / Dan MacNeil
Sponsor: Peter Schaffer / Dan MacNeil
PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 41
IPUC Data Request 41 In reference to the work papers provided in Response to Production Request No. 26, please explain how the “Goshen” shadow market price is representative of the
avoided cost of energy for the entire Idaho jurisdiction.

Response to IPUC Data Request 41
The PLEXOS model reports shadow market prices at each transmission area across the Company’s system. The Goshen load bubble represents the largest load bubble that is exclusive to Idaho and therefore is considered the most reasonable
for the Idaho jurisdiction. A portion of PacifiCorp’s Idaho and Wyoming loads are electrically contiguous with its Utah North transmission area and would have the same shadow market price as loads in that part of Utah, but a significant majority of the load in the Utah North transmission area is located within the state of Utah.

Recordholder: Peter Schaffer Sponsor: Peter Schaffer
PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 42
IPUC Data Request 42 In reference to the work papers provided in Response to Production Request No. 26, please explain how the "East 3 spinning" and "East 5 Regulation" reserves
classified as “System” in the “Reserve” input sheet are representative of the Idaho
jurisdiction. Response to IPUC Data Request 42

Referencing the Company’s response to IPUC Data Request 26, specifically Confidential Attachment IPUC 26, the nomenclature of “system” refers to the parent naming convention in the PLEXOS model being a part of the “Plexos system” meaning that it is part of the entire construct of the model. Reserves are values at the balancing authority area (BAA) level, the avoided cost model selects
values based on the PacifiCorp East (PACE) BAA, which is applicable to Idaho.
Recordholder: Peter Schaffer

Sponsor: Peter Schaffer
PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 43
IPUC Data Request 43 In reference to the work papers provided in Response to Production Request No. 26, please explain how the calculation isolates the avoided cost value of
contingent reserves from spinning and regulation reserve inputs.
Response to IPUC Data Request 43
Referencing the Company’s response to IPUC Data Request 26, specifically
Confidential Attachment IPUC 26, the avoided cost workbook has specific columns for spinning, non-spinning, and regulation reserves in tab “Calc” for each hour delineating their value. As constructed, the avoided cost workbook calculates reserve dispatch value based on regulation reserves, however, the program is capable of being dispatched for either regulation or contingency
reserves. To the extent a resource or program qualifies for multiple types of
reserves, it generally need not be designated for any particular type of reserves in advance, and may be dispatched for any of those requirements based on system needs at a particular time.

Recordholder: Peter Schaffer / Dan MacNeil Sponsor: Peter Schaffer / Dan MacNeil

PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 44
IPUC Data Request 44 In reference to the work papers provided in Response to Production Request No. 26, shown on the “Calc” tab, please confirm that there are no “non-spinning”
reserve values and provide an explanation why they are not used in the
calculations. Response to IPUC Data Request 44

Referencing the Company’s response to IPUC Data Request 26, specifically Confidential Attachment IPUC 26, there are non-spinning reserve values included in column K of tab “Calc”, and the shadow prices are zero throughout the study horizon because the Company has sufficient non-spinning reserve capability to meet its entire PacifiCorp East (PACE) balancing authority area (BAA)
requirement and those were not assumed to be available to meet other reserve
products. As a result, incremental East non-spinning reserve does not impact dispatch or result in a shadow price. To the extent there was a non-spinning reserve price, the calculation incorporates the value of reducing load when events
are called and the resulting reduction in the need for non-spinning reserves. As a
result of being calculated during an event, they are included in the value of an event column. However, the program is capable of dispatch for non-spinning reserves, but reserve values are not additive, the program can only be used for one category of reserves (contingency, regulation, frequency response) at any given moment. As constructed, the workbook assumes the program provides regulation
reserves during non-event hours, though the program could be used for non-
spinning and spinning reserves if necessary.
Recordholder: Peter Schaffer
Sponsor: Peter Schaffer
PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 45
IPUC Data Request 45 In reference to the work papers provided in Response to Production Request No. 26, shown on the “Calc” tab, why are spinning reserves and non-spinning reserves
included in the “Total Hourly Value of Event” calculation and not the “Total
Hourly Value of Event Reserves” calculation? Response to IPUC Data Request 45

An event reduces load, as well as the generation needed to serve that load. It therefore reduces the need for the Company to maintain spinning and non-spinning reserves by a total of 6 percent as required by North American Electric Reliability Corporation (NERC) regional reliability standard BAL-002-WECC-2a specifying that each balancing authority area (BAA) holds as contingency reserve
an amount of capacity equal to 3 percent of load and 3 percent of generation in
that BAA, with half of each required to be spinning and the remainder made up of non-spinning capability. Therefore, 3 percent of the spinning and non-spinning reserve value has been calculated as part of the “Total Hourly Value of Event”.

Recordholder: Peter Schaffer Sponsor: Peter Schaffer
PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 46
IPUC Data Request 46 In reference to the work papers provided in Response to Production Request No. 26, please provide the Company's definition of the reserve type associated with
“East 3 Spinning” reserve, the relevant North American Electric Reliability
Corporation (NERC) standard it is based on, and how the proposed program function provides that benefit.
Response to IPUC Data Request 46
“East 3 Spinning” represents contingency reserves for PacifiCorp’s East (PACE) balancing authority area (BAA), specifically for the 50 percent of the obligation that must be immediately responsive to system frequency deviations, and is used for compliance with North American Electric Reliability Corporation (NERC)
standard BAL-002-WECC-2a. For details, please refer to PacifiCorp’s 2021
Integrated Resource Plan (IRP), specifically Volume II, Appendix F (Flexible Reserve Study). PacifiCorp’s 2021 IRP is publicly available and can be accessed by utilizing the following website link:

Integrated Resource Plan (pacificorp.com) Recordholder: Dan MacNeil
Sponsor: Dan MacNeil

PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 47
IPUC Data Request 47 In reference to the work papers provided in Response to Production Request No. 26, please provide the Company’s definition of the reserve type associated with
“East 5 Regulation” reserve, the relevant NERC standard it is based on, and how
the proposed program function provides that benefit. Response to IPUC Data Request 47

“East 5 Regulation” represents regulation reserves for PacifiCorp’s East (PACE) balancing authority area (BAA), and is used for compliance with North American Electric Reliability Corporation (NERC) standard BAL-001-2. For details, please refer to PacifiCorp’s 2021 Integrated Resource Plan (IRP), specifically Volume II, Appendix F (Flexible Reserve Study). PacifiCorp’s 2021 IRP is publicly available
and can be accessed by utilizing the following website link:
Integrated Resource Plan (pacificorp.com)

Recordholder: Dan MacNeil Sponsor: Dan MacNeil
PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 48
IPUC Data Request 48 In reference to the work papers provided in Response to Production Request No. 26, please explain how the “Operating reserves” and “SCCT EIM Benefit” in
sheet “Capacity” differ from the reserves accounted for by the “Reserves” sheet?
Where are these numbers sourced, supported, and calculated? Please explain why “Operating Reserves” are removed in this way, but reserves are added to the avoided cost using hourly data from the “Reserves” sheet. Please further explain
whether the “Operating reserves” and “SCCT EIM Benefit” values of the
“Capacity” sheet overlap with the reserves accounted for by the “Reserves” sheet. Response to IPUC Data Request 48 “Capacity” value represents the incremental revenue requirement necessary to
ensure that PacifiCorp’s portfolio of resources can reliably meet its load service
obligations. All resources provide both capacity and energy, and energy benefits help to defray the cost of resources and reduce the revenue requirement that must be collected from customers. Energy benefits include both direct energy-cost
savings, and indirect savings as part of shifts in operating reserve requirements.
The cost savings associated with operating reserves and the margin earned as a result of energy imbalance market (EIM) dispatch would reduce the revenue requirement for a simple cycle combustion turbine (SCCT) that would be collected from customers. The remaining cost represents the cost of capacity
needed to ensure system reliability. After adjusting for the relative contributions
to reliability and adding an estimate of avoided transmission and distribution system costs (which apply to demand response (DR), but not to a utility scale natural gas plant) the resulting capacity value is appropriate to apply to DR. This
value only encompasses the capacity value or reliability benefit as extracted from
the proxy gas plant costs and operating characteristics. The value of the DR program also needs to include the equivalent reductions to revenue requirement associated with the specific energy and operating reserve benefits that the program is expected to provide.

Recordholder: Dan MacNeil Sponsor: Dan MacNeil
PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 49
IPUC Data Request 49 In reference to the work papers provided in Response to Production Request No. 26, please explain the source and reasoning for removing the “Operating
Reserves” and “SCCT EIM Benefit” shown on tab "Capacity”.
Response to IPUC Data Request 49
Referencing the Company’s response to IPUC Data Request 26, specifically
Confidential Attachment IPUC 26, the “Operating Reserves” and “SCCT EIM Benefit” values on tab “Capacity” are sourced from the Company’s most recent general rate case (GRC), Case PAC-E-21-07, specifically Confidential Exhibit No. 36 (Interruptible Product Value Update) to the Direct Testimony of Company witness, Craig M. Eller. “Operating Reserves” and “SCCT EIM Benefit” are
incorporated to account for benefits that other capacity resources can provide.
This results in presenting a net cost of capacity valuation which is a more accurate reflection of the actual cost of capacity for a deferred resource.
For ease of reference, please refer to Confidential Attachment IPUC 49 which
provides a copy of Confidential Exhibit No. 36 from Case PAC-E-21-07. 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.

Recordholder: Peter Schaffer
Sponsor: Peter Schaffer

PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 50
IPUC Data Request 50 In reference to the work papers provided in Response to Production Request No. 26, please explain the basis for using the “Avoided generation capacity costs –
2019 IRP, Bayer Contract” in the spreadsheet.
Response to IPUC Data Request 50
Referencing the Company’s response to IPUC Data Request 26, specifically
Confidential Attachment IPUC 26, the Company elected to use the “Avoided generation capacity costs – 2019 IRP, Bayer Contract” values because they are consistent with values already approved in Idaho as part of the most recent general rate case (GRC), Case PAC-E-21-07, specifically Confidential Exhibit No. 36 (Interruptible Product Value Update) to the Direct Testimony of Company
witness, Craig M. Eller. There are many deferred resources and techniques that
can be used for capacity valuation purposes. The Company used the recently approved values in this instance, in particular because the Bayer contract also involved demand response.

Please refer to the Company’s response to IPUC Data Request 49, specifically Confidential Attachment IPUC 49 which provides a copy of Confidential Exhibit No. 36 from Case PAC-E-21-07.
Recordholder: Peter Schaffer
Sponsor: Peter Schaffer

PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 51
IPUC Data Request 51 Please explain the basis for using “30 hours” in the top 30 high energy price hours in the model, while the other 30 hours are assumed to be on hand for potential
reserve dispatch.
Response to IPUC Data Request 51
Dispatch for energy or for reserves are at the utility’s discretion. The Company
elected to use an equal amount of hours between the two types of dispatch as it seemed reasonable given the program will likely be dispatched for both. However, the operator has discretion to dispatch more or less hours for energy price or reserve based on system requirements and market conditions. In actual operations, the probability of being called for reserve dispatch is not known in
advance, but a sufficient number of unused hours needs to be maintained to
ensure that the resources can be called upon when needed. The best hours for energy dispatch are also uncertain in actual operations, as what seems like high prices today could be below what prices are next week or next month. With that
uncertainty in mind, the split between energy dispatch and reserve dispatch was
intended to reasonably reflect likely future value. Recordholder: Peter Schaffer
Sponsor: Peter Schaffer

PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 52
IPUC Data Request 52 Are all costs shown on tabs “Energy” and “Reserve” devoid of any capacity cost? Please explain.
Response to IPUC Data Request 52 The Company assumes that the reference to “Energy” and “Reserve” tabs is
intended to be referring to the Company’s response to IPUC Data Request 26,
Confidential Attachment IPUC 26, tabs “Energy” and “Reserve”. Based on the foregoing assumption, the Company responds as follows: Yes. Furthermore, any capacity resource evaluated in PacifiCorp’s Integrated Resource Plan (IRP) would provide energy and reserve benefits based on these
values as part of the determination of its overall value.
Recordholder: Peter Schaffer

Sponsor: Peter Schaffer
PAC-E-22-13 / Rocky Mountain Power February 3, 2023 IPUC Data Request 53
IPUC Data Request 53 The yearly program avoided cost provided in Production Request No. 26 show a clear downward trend for both “E+C” and reserve components over the forecasted
5-year period. While these numbers will be updated in subsequent IRP’s, the
downward trend is concerning. How does the Company plan to retain the program benefit as it experiences the predicted decrease in avoided costs over the coming years?
Response to IPUC Data Request 53 The program retains flexibility to adjust dispatch to follow market value if one component experiences a reduction in value dispatch can be adjusted to follow higher value components. Additionally, the Company can adjust incentives to
reduce program costs to maintain cost-effectiveness. There is also potential for
setup costs, such as load control devices installed on customer equipment, to be less in years 6 through 10 as these costs will mostly be amortized in the initial years of the program as participation ramps up. The predicated reduction in
avoided cost at the end of the five-year period is, in part, due to procurement and
integration of large-scale utility batteries. Since PacifiCorp published its 2021 Integrated Resource Plan (IRP) in September 2021, higher than anticipated resource costs, along with the corresponding ongoing supply-chain issues have made the downward trend in energy and capacity and reserve values less likely to occur in the next five years.

Recordholder: Peter Schaffer
Sponsor: Peter Schaffer

1
Joe Dallas (ISB# 1033) Rocky Mountain Power 825 NE Multnomah, Suite 2000 Portland, OR 97232
Telephone: [phone] Email: [e-mail]
Attorney for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF ROCKY MOUNTAIN POWER’S APPLICATION FOR AUTHOIRTY TO IMPLEM,ENT A COMMERCIAL AND INDUSTRIAL DEMAND RESPONSE PROGRAM

-E-22-13

I, Joe Dallas , represent Rocky Mountain Power in the above captioned matter. I am an
attorney for Rocky Mountain Power.
I make this certification and claim of confidentiality regarding the response to the attached
Idaho Public Utilities Commission (“IPUC”) Staff discovery request pursuant to IDAPA 31.01.01
because Rocky Mountain Power, through its response, is disclosing certain information that is
Confidential and/or constitutes Trade Secrets as defined by Idaho Code Section 74-101, et seq.
and 48-801 and protected under IDAPA 31.01.01.067 and 31.01.01.233. Specifically, Rocky
Mountain Power asserts that attachment provided with the Company’s response to IPUC Staff data
requests 36, 40, and 49 contain Company proprietary information that could be used to its
commercial disadvantage.
RECEIVED
2023 February 3, 11:35AM
IDAHO PUBLIC
UTILITIES COMMISSION
2
Rocky Mountain Power herein asserts that the aforementioned response contains
confidential in that the information contains Company proprietary information.
I am of the opinion that this information is “Confidential,” as defined by Idaho Code
Section 74-101, et seq. and 48-801, and should therefore be protected from public inspection,
examination and copying, and should be utilized only in accordance with the terms of the
Protective Agreement in this proceeding.

DATED this 3th day of February, 2023.

Respectfully submitted,
By__________________________ Joe Dallas
Senior Attorney
Rocky Mountain Power