20230124Attachment 2-1 to Bayer.pdf

1407 W North Temple, Suite 330 Salt Lake City, Utah 84116
November 1, 2022 Jan Noriyuki Idaho Public Utilities Commission 472 W. Washington
Boise, ID 83702-5918 [e-mail] (C) RE: ID PAC-E-22-13
IPUC Set 1 (1-22) Please find enclosed Rocky Mountain Power’s Responses to IPUC 1st Set Data Requests 1-22. Also provided is Attachment IPUC 11. The Confidential Attachment IPUC 16 is 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/____ J. Ted Weston
Manager, Regulation
Enclosures
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 1
IPUC Data Request 1 Please explain and quantify how the commercial and industrial demand response program will directly benefit customers of Rocky Mountain Power in Idaho that
are not part of the program.
Response to IPUC Data Request 1
The 2021 Integrated Resource Plan (IRP) selected commercial and industrial demand response (DR) resources in Idaho as part of the Company’s preferred
portfolio. The preferred portfolio is an outcome of extensive stakeholder
engagement and optimization modeling in PLEXOS. The resources included in the preferred portfolio represent a least cost, least risk portfolio of resources to meet customer load. The marginal resource that would be procured in lieu of this DR program is more expensive or risky and therefore more costly to all customers in Idaho, even if they do not participate in the program. Recordholder: Peter Schaffer
Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 2
IPUC Data Request 2 Please explain the rationale for considering automated dispatch without advance notice with a total response time within 50 seconds as being considered a real-
time event. Please provide industry or Company referenced documentation
supporting these parameters. Application at 2. Response to IPUC Data Request 2

A demand response (DR) product must be capable of responding within 50
seconds to be qualified for a frequency response reserve. North American Electric
Reliability Corporation (NERC) reliability standard BAL-003-3 requires sufficient Frequency Response from a Balancing Authority (BA) or Frequency Response
Sharing Group. PacifiCorp is a member of Western Power Pool Frequency Response
Sharing Group. The defined Primary Response Evaluation Period is the first 50 seconds of the Frequency Response Event. Recordholder: Shawn Grant Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 3
IPUC Data Request 3 Please explain the rationale for considering a dispatched event with an advanced notice and a response within 7 minutes to be considered an advanced notice event.
Please provide industry or Company referenced documentation supporting the
parameters. Application at 2. Response to IPUC Data Request 3

North American Electricity Reliability Corporation (NERC) reliability standard BAL-002-WECC-3 requires that resources for Contingency Reserve Obligations are fully deployable within 10 minutes. Requiring seven minutes allows for communication and response time.

Recordholder: Shawn Grant Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 4
IPUC Data Request 4 Please explain the rational for the lower initial offered incentive amount of $100/kW if the customer is able to participate in Real Time Option. Application at
5.
Response to IPUC Data Request 4
Incentives are typically set at amounts the Company believes will spark
participation among customers. The Company believes the proposed incentives amounts will produce the anticipated participation. However, given that the proposed program is new, incentive levels and participation will be monitored and adjusted if needed to maintain participation levels

Recordholder: Shawn Grant Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 5
IPUC Data Request 5 Please explain the rational for the lower initial offered incentive amount of $100/kW if the customer is able to participate in Advance Notice Option.
Application at 5.
Response to IPUC Data Request 5
Please refer to the Company’s response to IPUC Data Request 4.

Recordholder: Shawn Grant Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 6
IPUC Data Request 6 Please explain the rational for the lower initial offered incentive amount of $175/kW if the customer is able to participate in both the Real Time and Advance
Notice Option. Application at 5.
Response to IPUC Data Request 6
Please refer to the Company’s response to IPUC Data Request 4.

Recordholder: Shawn Grant Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 7
IPUC Data Request 7 Please explain and quantify the amount of incentive a participant in the Demand Response program would receive if no events were called during the program
year. Application at 5.
Response to IPUC Data Request 7
If a program participant committed 1 megawatts (MW) of load to be available for
curtailment all 8,760 hours of the year and the Company called no events during the year, the customer would receive a $100,000 incentive (1,000 kilowatts (kW) x $100 per kW = $100,000). The MW committed to participate in the program provide value as a contingency reserve even when events are not actively being called.

Recordholder: Shawn Grant
Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 8
IPUC Data Request 8 Is the value of peak load reduction, contingency reserves, frequency response, and other grid services consistent throughout the year for the Company? If not, please
explain why the program incentives have fixed annual amounts.
Response to IPUC Data Request 8
The value for energy fluctuates depending on real-time market conditions. Factors such as, but not limited to, temperature, time, local generation constraints,
generation plant outages, weather, etc. impact the value of load. The fixed annual
incentive proposed in the program are a cost-effective amount for an annual incentive basis. Recordholder: Shawn Grant Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 9
IPUC Data Request 9 Please explain why the Wattsmart Business Demand Response Program should be managed through a flexible tariff process. Application at 7. In providing the
Company response, please indicate the circumstances that would change the
amount of the incentive and how often this would occur. Response to IPUC Data Request 9

Program offerings and incentive amounts are typically adjusted for reasons such
as program maturity, market transformation, increased or decreased program
participation, cost effectiveness maintenance, PacifiCorp’s Integrated Resource Plan (IRP), budget modifications, stakeholder feedback, etc. The frequency with which these events occur is intermittent, even with mature programs. Having a flexible tariff will help to manage this new program by enabling the Company to make swift adjustments if needed via the flexible tariff process and reduce risk. Recordholder: Shawn Grant
Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 10
IPUC Data Request 10 Please provide the website link to the program incentives referenced within the tariff.
Response to IPUC Data Request 10 A website specifically dedicated to an Idaho commercial and industrial program will not be developed until the program has been approved by the Idaho Public Utilities Commission (IPUC).

As an example, please refer to the website link provided below to the commercial and industrial demand response (DR) program approved by the Public Service Commission of Utah (UPSC): Demand Response (rockymountainpower.net) Recordholder: Shawn Grant
Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 11
IPUC Data Request 11 Please provide a listing of all current PacifiCorp Demand Response programs. The listing should identify each of the following items below:

(a) Jurisdiction/State. (b) Program Name. (c) Participant Type (i.e. residential, commercial, industrial, irrigation, other).
(d) Participant Count by Participant Type.
(e) Participant Commitment Period (i.e. full year, months, days, hours). (f) Program Dispatch Period. (g) Dispatch Days. (h) Available Dispatch Hours. (i) Maximum Dispatch Hours.
(j) Maximum Dispatch Events.
(k) Dispatch Duration. (l) Dispatch Notification. (m) Incentive.
(n) Methodology for Calculating the Participant Incentive.
(o) Opt-out Count by Participant Type. (p) Penalty for Opt-Out. (q) Total Enrolled MW (Gross - at Generator) for 2021. (r) Average Realized Load MW (at Generator) for 2021. (s) Maximum Realized Load MW (at Generator) for 2021.
Response to IPUC Data Request 11 Currently approved demand response (DR) programs include Oregon, Washington, Utah, and Idaho Irrigation Load Control programs, Utah Cool Keeper program, Utah and Idaho Wattsmart Batteries programs, and Utah’s
Wattsmart Business DR program. Please refer to Attachment IPUC 11 for the
requested details for each of these programs. Recordholder: Shawn Grant Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 12
IPUC Data Request 12 Please explain how each of the following program parameters were determined. In the explanation please include: (1) the rationale used (basis); (2) the work
papers of the calculations (or by using an example where appropriate); (3) the
specific source of information for any inputs. (a) initial and maximum incentives for real time option (Table No. 3),

(b) initial and maximum incentives for advance notice option (Table No. 3), (c) initial and maximum incentives for real time/advance notice option (Table No. 3),
(d) the amounts in Table No. 4,
(e) the amounts in Table No. 5,
(f) maximum dispatch hours for real time and advance notice programs,
(g) maximum events per year for the real time and advance notice programs, (h) dispatch duration for the real time and advanced notice programs, and
(i) the avoided cost used in the cost/benefit analysis in Exhibit C. Response to IPUC Data Request 12
(a) The maximum incentive is a dollar value per kilowatt (kW) determined to be cost effective based on the assumptions noted in Confidential Exhibit C in Case No. PAC-E-22-13. The initially offered incentive is a cost effective estimated amount anticipated to incent customers to participate. The incentive may increase or decrease as the program matures to achieve program goals.
(b) Please refer to the Company’s response to subpart (a) above.
(c) Please refer to the Company’s response to subpart (a) above.
(d) The amounts in Table 4 are based on planning estimates, participation estimates from Table 5, and contractual amounts from a third-party program administrator.
(e) The estimates in Table 5 are based on potential commercial and industrial customers in Idaho who have load that could participate in the proposed demand response (DR) program.
(f) The program parameters were designed to avoid customer participation fatigue
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 12
along with providing sufficient value for the Company as a resource. The maximum dispatch hours may change as the Company gains more experience after the program is implemented and attain program data and customer feedback.
(g) Please refer to the Company’s response to subpart (f) above.
(h) Please refer to the Company’s response to subpart (f) above.
(i) Please refer to the Company’s response to IPUC Data Request 16, specifically Confidential Attachment IPUC 16.
Recordholder: Shawn Grant
Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 13
IPUC Data Request 13 Why does the capacity factor not include when a customer's load is available for curtailment given that some customer's loads may occur only when the Company
has the highest amount of excess capacity?
Response to IPUC Data Request 13
The design and intent of the program is to provide an incentive to participants for
load available for curtailment. Customer incentives would be calculated based on hourly availability. If load is available, customers would receive an incentive or credit for being available. If there is no load available during certain hours customers would not receive an incentive for those hours.

Recordholder: Shawn Grant Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 14
IPUC Data Request 14 How can the incentive structure be modified to account for the time value of capacity?
Response to IPUC Data Request 14 The incentive structure is based on an annual kilowatt (kW) performance. Calculation of payment could theoretically weigh eligible loads by month or hours where capacity is more or less valuable or likely to be needed. However, for
frequency response services, events are unpredictable and therefore differentiating
value by hour or month may not reflect the actual value or need for capacity in a given hour of the year. Note: it is presently unknown how customers might respond to such an incentive structure. Recordholder: Shawn Grant Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 15
IPUC Data Request 15 Why are the combined advanced notice and real time participants priced higher than real time only participants?
Response to IPUC Data Request 15 Program participants who participate in the advance notice program and the real-time program receive a higher incentive because the load can be used for more demand response (DR) use cases and therefore provide more value and flexibility
to the Company.
Recordholder: Shawn Grant Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 16
IPUC Data Request 16 For the Company's cost-effectiveness calculation provided in Exhibit C, please provide the following in Excel format with all formulas enabled:

(a) Please provide all work papers for the cost effectiveness study shown in Exhibit C including all modeled assumptions;
(b) Please provide the Company's benefits calculation for each year for the entire
analysis period; (c) Please provide the benefits calculations from the Utility Cost Test (UCT) perspective; and
(d) Please provide the avoided cost used for the Company's benefits calculations
and brief explanation of how the Company calculates the avoided cost. Response to IPUC Data Request 16

Please refer to Confidential Attachment IPUC 16.

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: Shawn Grant Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 17
IPUC Data Request 17 How frequently (i.e., annually, quarterly, as needed, etc.) does the Company expect to consider program changes?
Response to IPUC Data Request 17 Program changes are typically based on a variety of factors, including program maturity, market transformation, increased or decreased program participation, cost effectiveness maintenance, PacifiCorp’s Integrated Resource Plan (IRP),
budget modifications, stakeholder feedback, etc. The frequency with which these
events occur is intermittent, even with mature programs. Based on these factors, and given that the proposed program will be new, the Company will consider program changes on an as needed basis, which may be frequent or sparse
depending on how the program performs.
Recordholder: Shawn Grant Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 18
IPUC Data Request 18 What criteria will the Company use to evaluate program changes?
Response to IPUC Data Request 18
The Company will consider items such as, but not limited to, program participation, incentive levels, customer satisfaction, PacifiCorp’s Integrated
Resource Plan (IRP), program energy savings, cost effectiveness, budget,
stakeholder feedback, market transformation, etc. Recordholder: Shawn Grant
Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 19
IPUC Data Request 19 Please provide estimates for the cost range, inventory requirements, O&M costs, reliability, and any other assumptions for the automatic transfer switches and
frequency relays. Please provide any additional documentation or worksheets to
support these estimates. Response to IPUC Data Request 19

The Company contracted with a program administrator (Enel X) who will be
responsible for equipment installation, technical configurations, and general
program management functions. Installations for automatic transfer switch will be handled by Enel X and will require a customized configuration based on the site and specific equipment to be curtailed. The estimated costs associated with the installation per Enel X could be $1,500 to $2,000 per site. The Company is assuming participation in Idaho from customers that can respond to frequency
response events that would require automatic transfer switches and/or frequency
relays to be low.
Recordholder: Shawn Grant
Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 20
IPUC Data Request 20 Please provide the reasoning for the proposed dispatch period and available dispatch hours.
Response to IPUC Data Request 20 The dispatch period is 24 hours-a-day, seven days-a-week, 365 days-a-year. A
comprehensive dispatch period is necessary to maximize the benefits associated
with this program. The dispatch hours were based on experience with previous programs and program retention. Recordholder: Shawn Grant

Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 21
IPUC Data Request 21 Please explain if there any operational, differing processes, or other differences between Demand Response programs and Energy Efficiency measures for the
flexible tariff process.
Response to IPUC Data Request 21
There are no operational, differing processes, or other differences between demand response (DR) and energy efficiency (EE) programs for the flexible tariff
process.
Recordholder: Shawn Grant Sponsor: Bill Comeau
PAC-E-22-13 / Rocky Mountain Power November 1, 2022 IPUC Data Request 22
IPUC Data Request 22 In the Company's Application, it is stated that the program may be used to provide other grid services. Application at 2. Please describe these other services and their
value to the proposed Demand Response program.
Response to IPUC Data Request 22
Other services cannot be fully defined or valued at this time. As the program evolves and the grid transitions over time, the Company will look for
opportunities to utilize demand response (DR) programs for additional grid
services as they apply. Any changes to DR programs will be implemented in compliance with regulatory and flexible tariff processes. Recordholder: Shawn Grant Sponsor: Bill Comeau
1407 W North Temple, Suite 330 Salt Lake City, Utah 84116
December 22, 2022 Jan Noriyuki Idaho Public Utilities Commission 472 W. Washington
Boise, ID 83702-5918 [e-mail] (C) RE: ID PAC-E-22-13
IPUC Set 2 (23-33) Please find enclosed Rocky Mountain Power’s Responses to IPUC 2nd Set Data Requests 23-33. The Confidential Response to Data Request IPUC 23 and Confidential Attachment IPUC 26 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
PAC-E-22-13 / Rocky Mountain Power December 22, 2022 IPUC Data Request 23
IPUC Data Request 23 Please provide estimates for the range in cost, inventory requirements, O&M costs, product life, reliability, and any other assumptions for the remote controlled
relays used for automated curtailment. Please provide any additional supporting
documentation or worksheets to support these estimates. Confidential Response to IPUC Data Request 23

The Company has a contractual set-up fee with a third-party vendor for per facility. This set-up fee includes hardware, labor, inventory, travel, and any other costs related to installing and maintaining equipment for automated controls and/or manual controls. If there is a need for additional equipment at a site, it
would require a custom bid based on the specific location and/or equipment.
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: Shawn Grant

Sponsor: Clay Monroe
PAC-E-22-13 / Rocky Mountain Power December 22, 2022 IPUC Data Request 24
IPUC Data Request 24 Please describe the Company's process for recovering physical devices if a participant drops out of the program. Please provide analysis of how the
additional costs associated with the retrieval of the device, if any, will affect the
program's cost effectiveness. Response to IPUC Data Request 24

To recover physical devices from previous program participant, the equipment would either be uninstalled by on-site maintenance staff, by a third-party program administrator, or by Company staff. The costs to retrieve these devices would be minimal and would be expected to have an immaterial impact to overall program cost effectiveness.

Recordholder: Shawn Grant
Sponsor: Clay Monroe
PAC-E-22-13 / Rocky Mountain Power December 22, 2022 IPUC Data Request 25
IPUC Data Request 25 Please describe the incentive structures the Company considered for the proposed program (i.e., individual rates for grid management functions such as peak load
reduction, contingency reserves, and frequency response, fixed annual incentive,
etc.) and the reasoning used to select the proposed fixed incentive structure. Response to IPUC Data Request 25

The proposed fixed incentive structure for this demand response (DR) program was ultimately selected for cost effectiveness and customer experience. The Company considered offering different incentive values based on different hours, days, and months of the year. The Company considered developing a sophisticated incentive structure for different use cases and hourly rates
throughout the year. Ultimately, the Company determined a sophisticated
incentive structure would be a deterrent for customer participation. An easy-to-understand fixed incentive structure is expected to be the best option for program adoption and success.

Recordholder: Shawn Grant Sponsor: Clay Monroe
PAC-E-22-13 / Rocky Mountain Power December 22, 2022 IPUC Data Request 26
IPUC Data Request 26 In Response to Production Request No. 8, the Company indicates that the value of energy fluctuates in response to several market conditions. Please provide an
explanation of how the Company tracks the fluctuation of these values and
provide the workpapers detailing the valuation of the different grid management functions with all formulas intact and enabled.
Response to IPUC Data Request 26
Real-time operations’ monitors reserve holdings and locational marginal prices (LMP) on a continuous basis. Operators use the energy management system (EMS) and Pi Historian to monitor total reserve holdings to determine sufficiency meeting reserve obligations as a member of the Western Power Pool Reserve
(WPP) Sharing Group. Operators monitor individual resources for performance
and demand response (DR) programs holding reserves using the EMS, Pi Historian, and the Yukon application which administers the CoolKeeper program. Additionally, real-time operations’ monitors LMP for energy using SettleCore
software and California Independent System Operator (CAISO) applications.
The Company’s current process for DR valuation generally work as follows: Contingency Reserves - to count as contingency reserve, resources must respond within 10 minutes following a loss of generation or transmission. These events
typically last less than 60 minutes. The Company has a number of different load control resources that could be deployed and depending on the magnitude of the need and contractual details related to the frequency and duration of events, system operators will deploy one or more resources when an event occurs. On a
forecast basis, the Company’s Integrated Resource Plan (IRP) production cost modeling tool, PLEXOS, reports the marginal cost of holding contingency reserves on an hourly basis, and the results from the IRP preferred portfolio are used for DR program analysis. Frequency Response – to count as frequency response, resources must respond
within seconds to a dip in the frequency of the Western Interconnect. The Company currently has automated processes which deploy the Coolkeeper Air Conditioning Control program in response to frequency events. These events
typically last less than 10 minutes. When they are enabled for frequency response,
all available frequency responsive resources respond automatically to frequency events. The PLEXOS model is not configured to account for frequency response requirements, which overlap with spinning reserves. Energy, peak load reduction, and other grid services - when DR is available
and not being held ready for one of the short-notice reserve products above, it can
be deployed to provide energy value, which may occur during peak load periods.
PAC-E-22-13 / Rocky Mountain Power December 22, 2022 IPUC Data Request 26
To the extent the Company has DR available to call on, it can avoid market purchases or not start-up thermal resources that might be needed to cover peak load hours. The PLEXOS model reports the marginal energy cost by location, and results from the IRP preferred portfolio are used for DR program analysis.

Please refer to Confidential Attachment IPUC 26 which provides the work paper detailing the Company’s valuation of the grid management functions.
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: Clay Monroe

PAC-E-22-13 / Rocky Mountain Power December 22, 2022 IPUC Data Request 27
IPUC Data Request 27 Please explain how the Company intends to report on the proposed program.
Response to IPUC Data Request 27
If the proposed program is approved, the Company intends to report on the program annually within the pre-existing Demand-Side Management (DSM)
Annual Report, consistent with other demand response (DR) program reporting.
Recordholder: Shawn Grant Sponsor: Clay Monroe
PAC-E-22-13 / Rocky Mountain Power December 22, 2022 IPUC Data Request 28
IPUC Data Request 28 Please explain how the Company will evaluate and report the performance and cost-effectiveness of the program. Please include all metrics, such as cost,
savings, and any other metrics the Company plans to use in its evaluation.
Response to IPUC Data Request 28
The Company will consult with third-party evaluators to determine the best
methodology for evaluating the proposed commercial and industrial demand response (DR) program. It is anticipated the evaluation will include items such as kilowatt (kW) savings, cost effectiveness, customer experience, etc.
Recordholder: Shawn Grant
Sponsor: Clay Monroe
PAC-E-22-13 / Rocky Mountain Power December 22, 2022 IPUC Data Request 29
IPUC Data Request 29 Please explain the Company's intentions for evaluating the program? (i.e., process and impact evaluations)
Response to IPUC Data Request 29 The Company intends to discuss evaluation options in future stakeholder meetings
with Idaho Public Utilities Commission (IPUC) staff. The program would need to
have sufficient participation levels before an evaluation would provide meaningful data. Recordholder: Shawn Grant

Sponsor: Clay Monroe
PAC-E-22-13 / Rocky Mountain Power December 22, 2022 IPUC Data Request 30
IPUC Data Request 30 In the confidential worksheet provided in Response to Production Request No. 16, Utah export credit values for energy and capacity (energy+cap) and incremental
reserves are provided and used to calculate the benefits for the proposed program.
Please answer the following questions related to the Utah export credit values: (a) Please describe the reasoning for using Utah values for an Idaho program.

(b) Please identify the risk associated with using Utah values for Idaho and how the Company accounted for them. (c) Please provide work papers for the energy+cap and incremental reserve export credit values in electronic format with formulas intact. Please include a
detailed description and examples of how these values are calculated.
(d) The Company uses the sum of 2022 energy+cap and incremental reserve export credit values to calculate the benefits in 2023. Please explain why 2022
export credits are used to calculate 2023 benefits.
Response to IPUC Data Request 30 (a) An Idaho-specific value for commercial and industrial demand response (DR) was not available at the time of filing. The Company utilized the
calculated value for Utah to calculate an estimated cost effectiveness for the
proposed program. Idaho-specific values were developed for cost effectiveness for this proposed program and recalculated to ensure the proposed program is still cost effective. Please refer to the Company’s
response to IPUC Data Request 26, specifically Confidential Attachment
IPUC 26, which provides a copy of the work paper supporting the development of Idaho-specific values. (b) The risks of using Utah-specific values to estimate proposed cost effectiveness are limited. It was assumed the values for Idaho would be
very similar to values calculated for Utah as market prices for energy and
reserves are relatively similar between the two states. (c) Please refer to the Company’s response to IPUC Data Request 26, specifically Confidential Attachment IPUC 26, which provides a copy of the work paper supporting the development of Idaho-specific energy+cap and incremental reserve values. (d) The Company proposed cost effectiveness assuming five years of cumulative megawatts (MW) for curtailment along with five years of total program costs.
The Company elected to use annual values starting with 2022 values, with the
PAC-E-22-13 / Rocky Mountain Power December 22, 2022 IPUC Data Request 30
assumption current values would be more accurate than values five years into the future. In lieu of Utah export credit values, Idaho-specific values were developed for cost effectiveness for this proposed program and recalculated to ensure the proposed program is still cost effective. Please refer to the
Company’s response to IPUC Data Request 26, specifically Confidential
Attachment IPUC 26, which provides a copy of the work paper supporting the development of Idaho-specific values.

Recordholder: Shawn Grant Sponsor: Clay Monroe
PAC-E-22-13 / Rocky Mountain Power December 22, 2022 IPUC Data Request 31
IPUC Data Request 31 Does the Company intend to use the Commercial and Industrial Demand Response program as part of a "flexible load" program? If so, please explain the
Company's approach to the "flexible" load program. If not, please explain why the
Company has not considered this approach as part of its Demand Response program.
Response to IPUC Data Request 31
The Company’s interprets “flexible load” to mean loads that can shift the timing of demand, or modify the timing of demand, to optimize based on prices, emissions, or other priorities. Based on the foregoing interpretation, the Company responds as follows:

The proposed program was designed for customers who have consistent load available for curtailment. Customers are compensated based on their specific load available for curtailment throughout a calendar year and participation in
scheduled events. Customers who have “flexible load” may participate in the
proposed program. Depending on the type of customers who have “flexible load” may or may not be a good fit for a real-time program depending on the flexibility of their industry (e.g. start and stop production lines, real-time modification of business operations, etc.).

Recordholder: Shawn Grant Sponsor: Clay Monroe
PAC-E-22-13 / Rocky Mountain Power December 22, 2022 IPUC Data Request 32
IPUC Data Request 32 Does the Company intend to use the Commercial and Industrial Demand Response program to allow for intraday shifting of electricity use during hours
with high electricity prices or peak load (i.e. load shifting)? If so, please explain
the Company's approach to "load shifting" within the program. If not, please explain why the Company has not considered this approach as part of its Demand Response program.
Response to IPUC Data Request 32 The Company interprets “load shifting” to include time-of-day (TOD) rates, on-peak rates / off-peak rates, and market-based rates. Based on the foregoing interpretation, the Company responds as follows:

The initial design of the program did not consider “load shifting” as the program was designed to curtail customer load (megawatts (MW)) from the electric grid when activated.

Recordholder: Shawn Grant Sponsor: Clay Monroe
PAC-E-22-13 / Rocky Mountain Power December 22, 2022 IPUC Data Request 33
IPUC Data Request 33 In reference to Table 6 on page 6 of the Application, please explain why the values for Maximum Dispatch Hours, Maximum Events per year, and the
Dispatch Duration for the Real-Time Program and the Advance Notice Program
differ from or are not shown in proposed changes to the load management flexible tariff identified in Exhibit B of the Application.
Response to IPUC Data Request 33
Table 6 of the Company’s Application lists the granular dispatch parameter details for the Real-Time and Advance Notice components of the program, whereas the dispatch parameter table in Exhibit B of the Company’s Application reflects the maximum combined parameters. For example, the maximum dispatch
hours for the Real-Time and Advance Notice options in Table 6 are five hours and
60 hours respectively, so the combined maximum hours listed in Exhibit B is 65 hours. The Exhibit B flexible tariff table is meant to provide the high-level maximum overview that can be updated as necessary through the flexible tariff
process. The Company’s website will list the granular information which
customers will be able to access. This is similar to how the Company’s other demand-side management (DSM) flexible tariffs operate. With respect to the Maximum Events per year parameter, this detail was inadvertently omitted from the table in Exhibit B. Table 6 lists the maximum
events for the Real-Time and Advance Notice options at 50 events and 25 events
per year, respectively. The table below from Exhibit B has been updated to incorporate the maximum events per year parameter, listing the total combined maximum events at 75.

Load Control Program Dispatch Period Dispatch Hours / Events Dispatch Days Dispatch Duration
Wattsmart Batteries 5-Year Pilot
January 1 through December 31
12:00am to
11:59pm Mountain Time Not applicable
Monday
through Sunday
multiple times per day up to two full battery
Wattsmart Business Demand January 1 through
December 31 11:59pm 65 hours / 75 events through Events will be limited to
four hours per day
Recordholder: Shawn Grant Sponsor: Clay Monroe
1
Joe Dallas (ISB #10330) 825 NE Multnomah, Suite 2000 Portland, OR 97232 Telephone No. [phone]
Email: [e-mail] Attorney for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
FOR

-E-22-13
DISCOVERY

I, Joe Dallas, represent Rocky Mountain Power in the above captioned matter. I am an
attorney for Rocky Mountain Power.
I make this certification and claim of confidentiality regarding the response to the attached
Idaho Public Utilities Commission Staff discovery request pursuant to IDAPA 31.01.01 because
Rocky Mountain Power, through its response, is disclosing certain information that is Confidential
and/or constitutes Trade Secrets as defined by Idaho Code Section 74-101, et seq. and 48-801 and
protected under IDAPA 31.01.01.067 and 31.01.01.233. Specifically, Rocky Mountain Power
asserts that Confidential Attachment IPUC 16 provided with the Company’s response to IPUC
Data Requests No. 12 and 16 contain Company proprietary information that could be used to its
commercial disadvantage.
2
Rocky Mountain Power herein asserts that the aforementioned responses contain
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.

DATED this 1st day of November, 2022.

Respectfully submitted,
By__________________________ Joe Dallas Senior Attorney Rocky Mountain Power

1
Joe Dallas (ISB #10330) 825 NE Multnomah, Suite 2000 Portland, OR 97232 Telephone No. [phone]
Email: [e-mail] Attorney for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
MATTER OF THE APPLICATION
\D INDUSTRIAL \D RESPONSE PROGRAM

-E-22-13
SES

I, Joe Dallas, represent Rocky Mountain Power in the above captioned matter. I am a
senior attorney for Rocky Mountain Power.
I make this certification and claim of confidentiality regarding the response to the attached
Idaho Public Utilities Commission Staff discovery request pursuant to IDAPA 31.01.01 because
Rocky Mountain Power, through its response, is disclosing certain information that is Confidential
and/or constitutes Trade Secrets as defined by Idaho Code Section 74-101, et seq. and 48-801 and
protected under IDAPA 31.01.01.067 and 31.01.01.233. Specifically, Rocky Mountain Power
asserts that information contained within the Company’s response IPUC Data Request No. 23 and
attachments provided with the Company’s response to IPUC Data Requests No. 26 contain
Company proprietary information that could be used to its commercial disadvantage.
2
Rocky Mountain Power herein asserts that the aforementioned responses contain
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 22nd day of December, 2022.

Respectfully submitted,
By__________________________ Joe Dallas
Senior Attorney
Rocky Mountain Power

Oregon Irrigation Load Control Program
a. Jurisdiction/State – Oregon
b. Program Name – Irrigation Load Control
c. Participant Type (i.e. residential, commercial, industrial, irrigation, other) Irrigation
Customers on Schedules 41 or 48.
d. Participant Count by Participant Type – 5 irrigation customers participated in both the
2021 and 2022 season
e. Participant Commitment Period (i.e. full year, months, days, hours) – participants
agree to enroll and participate through December 31, 2026 with the ability to unenroll
with no penalty, upon request. If unenrollment occurs during the dispatch period, it may
impact their final incentive amount. Assuming the program continues beyond that date,
customers will be able to remain enrolled.
f. Program Dispatch Period – June 1st – Sept. 15th
g. Dispatch Days – All days during dispatch period
h. Available Dispatch Hours – Noon – 10pm
i. Maximum Dispatch Hours – 52 hours per year
J. Maximum Dispatch Events – 20 events per year
k. Dispatch Duration – 4 hours max per event
I. Dispatch Notification – day-ahead, hour-ahead, and 20-minute ahead notifications.
m. Incentive - $18/kW, $30/kW, and $45/kW for day-ahead, hour-ahead, and 20-minute-
ahead dispatch notifications, respectively.
n. Methodology for Calculating the Participant Incentive – The incentive payment is
calculated at the end of the irrigation season and paid to each participant after the season
ends. Participant incentives are determined by multiplying the average load (kW) a
customer can reliably shut-off during program hours by the incentive rate, adjusted for
event participation (opt-outs).
o. Opt-out Count by Participant Type – in the 2021 season, one customer opted two pumps
out of all events to prevent flooding and none of the participants opted out of events during
the 2022 season
p. Penalty for Opt-Out – there is no fee or “penalty” for opting out of an event that the
customer must pay and there are no limits on a customer’s ability to opt out; rather the final
incentive payout at the end of the season is reduced proportional to the amount of opt outs
(see item n. above).
q. Total Enrolled MW (Gross - at Generator) for 2021 — 0.473 MW average available
load enrolled (i.e. participants’ average baseline demand) at customer site converts to
0.516 MW average available at generator using the 8.467% line loss factor from the
2018 line loss study from the Oregon General Rate Case
r. Average Realized Load MW (at Generator) for 2021 – 0.36 MW average reduction at
customer site converts to 0.393 MW average reduction at generator using the 8.467%
line loss factor from the 2018 line loss study from the Oregon General Rate Case
s. Maximum Realized Load MW (at Generator) for 2021 – the highest actual load
reduction during events from the 2021 season was 0.459 MW at customer site, which
converts to 0.501 MW at generator using the 8.467% line loss factor from the 2018 line loss
study from the Oregon General Rate Case

Washington Irrigation Load Control Program
a. Jurisdiction/State – Washington
b. Program Name – Irrigation Load Control
c. Participant Type (i.e. residential, commercial, industrial, irrigation, other) Irrigation
Customers on Schedules 40.
d. Participant Count by Participant Type – currently zero irrigation customers have enrolled
e. Participant Commitment Period (i.e. full year, months, days, hours) – participants
agree to enroll and participate through December 31, 2026 with the ability to unenroll
with no penalty, upon request. If unenrollment occurs during the dispatch period, it may
impact their final incentive amount. Assuming the program continues beyond that date,
customers will be able to remain enrolled.
f. Program Dispatch Period – June 1st – Sept. 15th
g. Dispatch Days – All days during dispatch period
h. Available Dispatch Hours – Noon – 10pm
i. Maximum Dispatch Hours – 52 hours per year
j. Maximum Dispatch Events – 20 events per year
k. Dispatch Duration – 4 hours max per event
l. Dispatch Notification – day-ahead, hour-ahead, and 20-minute ahead notifications.
m. Incentive - $18/kW, $30/kW, and $45/kW for day-ahead, hour-ahead, and 20-minute-
ahead dispatch notifications, respectively.
n. Methodology for Calculating the Participant Incentive – The incentive payment is
calculated at the end of the irrigation season and paid to each participant after the season
ends. Participant incentives are determined by multiplying the average load (kW) a
customer can reliably shut-off during program hours by the incentive rate, adjusted for
event participation (opt-outs).
o. Opt-out Count by Participant Type – n/a (no participation in the 2022 season)
p. Penalty for Opt-Out – there is no fee or “penalty” for opting out of an event that the
customer must pay and there are no limits on a customer’s ability to opt out; rather the final
incentive payout at the end of the season is reduced proportional to the amount of opt outs
(see item n. above).
q. Total Enrolled MW (Gross - at Generator) for 2021 – N/A (no program in 2021)
r. Average Realized Load MW (at Generator) for 2021 – N/A (no program in 2021)
s. Maximum Realized Load MW (at Generator) for 2021 – N/A (no program in 2021)

Idaho Irrigation Load Control Program

a. Jurisdiction/State – Idaho
b. Program Name – Irrigation Load Control
c. Participant Type (i.e. residential, commercial, industrial, irrigation, other) Irrigation
Customers on Schedule 10.
d. Participant Count by Participant Type – 167 Customers/1,204 sites in 2021
e. Participant Commitment Period (i.e. full year, months, days, hours) – 5 years/Opt-Out
any time.
f. Program Dispatch Period – May 1st through September 30th
g. Dispatch Days – Monday through Friday, excluding holidays
h. Available Dispatch Hours – 2:00pm – 9:00pm Mountain Time
i. Maximum Dispatch Hours – 12 hours per week / 52 hours per year
j. Maximum Dispatch Events – 1 event per day
k. Dispatch Duration – 4 hours maximum per event
l. Dispatch Notification – 4 hour minimum
m. Incentive – Customer compensation is determined by multiplying the average kilowatt (kW)
load a customer can reliably shut-off during program hours by the incentive rate, adjusted for
event participation. Each customer’s incentive rate is set by his or her average expected kW
per pump

Average Expected
kW per pump
Based Incentive
Rate ($/kW)
Bonus Incentive Rate ($/kW)
*if program is > 125 MW
Over 100 kW $23 $25
Under 100 kW $19 $21
n. Methodology for Calculating the Participant Incentive – Please refer to the response to
subpart (m) above.
o. Opt-out Count by Participant Type – 12.69 percent opt out rate.
p. Penalty for Opt-Out – Incentive adjustment
q. Total Enrolled MW (Gross - at Generator) for 2021 – 193 Megawatts
r. Average Realized Load MW (at Generator) for 2021 – 119 Megawatts
s. Maximum Realized Load MW (at Generator) for 2021 – 155 Megawatts

Utah Irrigation Load Control Program

a. Jurisdiction/State – Utah
b. Program Name – Irrigation Load Control
c. Participant Type (i.e. residential, commercial, industrial, irrigation, other) Customers
served by the Company in Utah taking services under electric service Schedule 10.
d. Participant Count by Participant Type – 31 Customers/131 sites in 2021
e. Participant Commitment Period (i.e. full year, months, days, hours) – 5 years/Opt-Out
any time.
f. Program Dispatch Period – May 1st through September 30th
g. Dispatch Days – Monday through Friday, excluding holidays
h. Available Dispatch Hours – 2:00pm – 9:00pm Mountain Time
i. Maximum Dispatch Hours – 12 hours per week / 52 hours per year
j. Maximum Dispatch Events – 1 event per day
k. Dispatch Duration – 4 hours maximum per event
l. Dispatch Notification – 4 hours minimum
m. Incentive – Customer compensation is determined by multiplying the average kilowatt (kW)
load a customer can reliably shut-off during program hours by the incentive rate, adjusted for
event participation. Each customer’s incentive rate is set by his or her average expected kW
per pump

Average Expected
kW per pump
Based Incentive
Rate ($/kW)
Bonus Incentive Rate ($/kW)
*if program is > 125 MW
Over 100 kW $25 $27
Under 100 kW $21 $23
n. Methodology for Calculating the Participant Incentive – Please refer to the response to
subpart (m) above.
o. Opt-out Count by Participant Type – 56.47% opt out rate
p. Penalty for Opt-Out – Incentive adjustment
q. Total Enrolled MW (Gross - at Generator) for 2021 – 14 Megawatts at gen, 13 at site
r. Average Realized Load MW (at Generator) for 2021 – 3 Megawatts at site
s. Maximum Realized Load MW (at Generator) for 2021 – 4 Megawatts at site

Utah Cool Keeper Program

a. Jurisdiction/State – Utah
b. Program Name – Cool Keeper
c. Participant Type (i.e. residential, commercial, industrial, irrigation, other) Customers
served by the Company in Utah taking services under electric service schedules listed
on Schedule 193.
d. Participant Count by Participant Type – 93,904 Customers in 2021
e. Participant Commitment Period (i.e. full year, months, days, hours) – None
f. Program Dispatch Period – May 1st through September 30th
g. Dispatch Days – Monday through Friday, excluding holidays
h. Available Dispatch Hours – 2:00pm – 9:00pm Mountain Time
i. Maximum Dispatch Hours – 100 hours per year
j. Maximum Dispatch Events – No limit
k. Dispatch Duration – 4 hours maximum per event
l. Dispatch Notification – None
m. Incentive – Customers who participate will receive a monthly credit each year, even if no
event are called. The thank-you credits are provided on customer bills during May through
September billing cycles. Partial credits are applied when enrollment begins after the start of
the cooling season (May 1). Participants who enroll after October 1 receive the full credit in
the following year.

Equipment Size Bill Credit
< 65,000 Btu/hr (5.4 tons) $30
> 65,000 Btu/hr or
< 180,000 Btu/hr (5.4 – 15 tons) $60
n. Methodology for Calculating the Participant Incentive – Please refer to the response to
subpart (m) above.
o. Opt-out Count by Participant Type –Not tracked
p. Penalty for Opt-Out – No penalty, however if a customer opts out several times they may
be subject to removal from the program.
q. Total Enrolled MW (Gross - at Generator) for 2021 – 270 Megawatts at gen, 254 at
site
r. Average Realized Load MW (at Generator) for 2021 – 93 Megawatts at site
s. Maximum Realized Load MW (at Generator) for 2021 – 220 Megawatts at site

Utah Wattsmart Batteries Program

a. Jurisdiction/State – Utah
b. Program Name – Wattsmart Batteries
c. Participant Type (i.e. residential, commercial, industrial, irrigation, other) Customers
served by the Company in Utah taking services under electric service schedules listed
on Schedule 193.
d. Participant Count by Participant Type – Approximately 800 residential in 2021
e. Participant Commitment Period (i.e. full year, months, days, hours) – 4 years
minimum
f. Program Dispatch Period – January 1st through December 31st
g. Dispatch Days – Monday through Sunday
h. Available Dispatch Hours – 12:00am – 11:59pm Mountain Time
i. Maximum Dispatch Hours – N/A
j. Maximum Dispatch Events – No maximum limit
k. Dispatch Duration – Events may be held multiple times per day up to two full battery
duty cycles
l. Dispatch Notification – No advance notification
m. Incentive – Participating customers receive a one-time enrollment incentive based on the
size of the enrolled battery as well as an ongoing annual participation incentive. If a
residential customer enrolls a 6-kilowatt (kW) battery with a commitment term of 4 years,
their enrollment incentive will be $3,600 (6kW x $150 x 4 years). During the commitment
period for years 2 – 4, the program participation annual incentive would be $90 (6kW x $15).
Furthermore, if the same customer continues to participate beyond the 4-year commitment
term, their annual participation incentive could be up to $300 (6kW x $50) as a $25 monthly
bill credit ($300 / 12 months). If a customer opts out of participating after their commitment
term, their annual participation incentive will be pro-rated.
n. Methodology for Calculating the Participant Incentive –
Load
Management
Program
Participating
Equipment
Maximum Incentive “up to”
Enrollment Incentive
Annual Participation
Incentive During
Commitment Term
Annual
Participation
Incentive
Wattsmart
Batteries
Residential
Batteries
$150/kW x Annual
Commitment Term $15/kW $50/kW
Commercial
Batteries
$150/kW x Annual
Commitment Term $15/kW $50/kW
o. Opt-out Count by Participant Type – None
p. Penalty for Opt-Out – Removal from the program and payback of upfront incentive.
q. Total Enrolled MW (Gross - at Generator) for 2021 – 6 Megawatts at gen
r. Average Realized Load MW (at Generator) for 2021 – 3 to 6 Megawatts program
continually increasing
s. Maximum Realized Load MW (at Generator) for 2021 – 6 Megawatts

Utah Wattsmart Business Demand Response Program

a. Jurisdiction/State – Utah
b. Program Name – Wattsmart Business Demand Response
c. Participant Type (i.e. residential, commercial, industrial, irrigation, other) Customers
served by the Company in Utah taking services under electric service schedules listed
on Schedule 193.
d. Participant Count by Participant Type – Program currently in start-up phase
e. Participant Commitment Period (i.e. full year, months, days, hours) – 5 year expected
term
f. Program Dispatch Period – January 1st through December 31st
g. Dispatch Days – Monday through Sunday
h. Available Dispatch Hours – 12:00am – 11:59pm Mountain Time
i. Maximum Dispatch Hours – 65 hours per year
j. Maximum Dispatch Events – Not Limited
k. Dispatch Duration – 4 hours per day
l. Dispatch Notification – 7 minutes
m. Incentive – Participating customers are compensated annually based on the verifiable load
that is available for dispatch throughout the year. Customer incentives are calculated based
on available kilowatt (kW) load during a program year and adjusted by capacity factor
(percentage of year load was available) and event performance percentage. For example, if a
customer had 1 MW of load on eligible equipment enrolled with a 50% capacity factor for
the advance notice program and the customer participated in 75% of the called events the
customer would receive a $37,500 incentive. ((1,000 kW x $100) x 50% x 75% = $37,500)
n. Methodology for Calculating the Participant Incentive –
Load Management
Program Participating
Equipment
Maximum
incentive
“up to”
Currently
Offered
Incentive
Real Time Option Commercial and
Industrial Custom $125/kW $100/kW Advance Notice Option
Real Time & Advance
Notice Option
Commercial and
Industrial Custom $190/kW $175/kW
o. Opt-out Count by Participant Type – N/A (no program in 2021)
p. Penalty for Opt-Out – There is no penalty for opting out. Customer incentives are based on
available load during a program year. See response to subpart (m) above.
q. Total Enrolled MW (Gross - at Generator) for 2021 – N/A (no program in 2021)
r. Average Realized Load MW (at Generator) for 2021 – N/A (no program in 2021)
s. Maximum Realized Load MW (at Generator) for 2021 – N/A (no program in 2021)

Idaho Wattsmart Batteries Program

a. Jurisdiction/State – Idaho
b. Program Name – Wattsmart Batteries Program
c. Participant Type (i.e. residential, commercial, industrial, irrigation, other) Customers
served by the Company in Idaho taking services under electric service schedules
listed on Schedule 191.
d. Participant Count by Participant Type – Program currently in start-up phase
e. Participant Commitment Period (i.e. full year, months, days, hours) – 4 year minimum
commitment
f. Program Dispatch Period – January 1st through December 31st
g. Dispatch Days – Monday through Sunday
h. Available Dispatch Hours – 12:00am – 11:59pm Mountain Time
i. Maximum Dispatch Hours – N/A
j. Maximum Dispatch Events – Not Limited
k. Dispatch Duration – Events may be held multiple times per day up to two full battery
duty cycles
l. Dispatch Notification – No advance notification
m. Incentive – Participating customers receive a one-time enrollment incentive based on the
size of the enrolled battery as well as an ongoing annual participation incentive. If a
residential customer enrolls a 5-kilowatt (kW) battery with a commitment term of 4 years,
their enrollment incentive will be $3,000 (5kW x $150 x 4 years). During the commitment
period for years 2 – 4, the program participation annual incentive would be $75 (5kW x $15).
Furthermore, if the same customer continues to participate beyond the 4-year commitment
term, their annual participation incentive could be up to $250 (5kW x $50). If a customer opts
out of participating after their commitment term, their annual participation incentive will be
pro-rated.
n. Methodology for Calculating the Participant Incentive –
Load
Management
Program
Participating
Equipment
Maximum Incentive “up to”
Enrollment Incentive
Annual Participation
Incentive During
Commitment Term
Annual
Participation
Incentive
Wattsmart
Batteries
Residential
Batteries
$150/kW x Annual
Commitment Term $15/kW $50/kW
Commercial
Batteries
$150/kW x Annual
Commitment Term $15/kW $50/kW
o. Opt-out Count by Participant Type – N/A (no program in 2021)
p. Penalty for Opt-Out – Removal from the program and payback of upfront incentive.
q. Total Enrolled MW (Gross - at Generator) for 2021 – N/A (no program in 2021)
r. Average Realized Load MW (at Generator) for 2021 – N/A (no program in 2021)
s. Maximum Realized Load MW (at Generator) for 2021 – N/A (no program in 2021)