20240124Application - REDACTED.pdf

1407 W. North Temple, Suite 330 Salt Lake City, Utah 84116 January 24, 2024

VIA ELECTRONIC FILING Idaho Public Utilities Commission 11331 W. Chinden Blvd. Building 8 Suit 201A
Boise, ID 83714
Attn: Commission Secretary RE: CASE NO. PAC-E-24-02
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER REQUESTING APPROVAL FOR ADJUSTMENTS TO THE IRRIGATION LOAD CONTROL PROGRAM
Please find enclosed for filing in the above captioned matter Rocky Mountain Power’s Application
requesting an order approving changes to the Irrigation Load Control program. Informal questions related to this matter may be directed to Michael Snow at [phone] or Mark Alder at [phone].

Sincerely,
Michael S. Snow
Manager, Regulatory Affairs Enclosures

cc: Eric Olsen
RECEIVED
Wednesday, January 24, 2024 4:36PM
IDAHO PUBLIC
UTILITIES COMMISSION
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Joseph M. Dallas, (ISB# 10330) Senior Attorney PacifiCorp 825 NE Multnomah, Suite 2000 Portland, Oregon 97232 Telephone: [phone] Email: [e-mail]

Attorney for Rocky Mountain Power
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER
REQUESTING APPROVAL FOR
ADJUSTMENTS TO THE IRRIGATION
LOAD CONTROL PROGRAM
) CASE NO. PAC-E-24-02
)
) APPLICATION
)
COMES NOW, Rocky Mountain Power, a division of PacifiCorp (the “Company” or
“Rocky Mountain Power”), in accordance with Idaho Code §61-502, §61-503, and RP 052,
hereby respectfully submits this application (“Application”) to the Idaho Public Utilities
Commission (“Commission”) to make adjustments to the Irrigation Load Control Program
(“ILC Program”).
In support of this Application, Rocky Mountain Power states as follows:
1. Rocky Mountain Power is authorized to do and is doing business in the state of
Idaho as a public utility providing retail electric service to approximately 88,780 customers.
Rocky Mountain Power is a public utility subject to the jurisdiction of the Commission
pursuant to Idaho Code § 61-129.
I. BACKGROUND
2. On December 7, 2012, the Company filed an application in Case
No. PAC-E-12-14 requesting authority to cancel Electric Service Schedule Nos. 72 and 72A
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Irrigation Load Control tariffs and approve a new 10-year contract with EnerNoc, now known
as Enel X North America, Inc. (“Enel X”), to administer the ILC Program.
3. On February 7, 2013, the Company and Idaho Irrigation Pumpers Association
filed a Stipulation to amend various sections of the Company’s contract with EnerNoc.
4. On March 8, 2013, the Commission issued Order No. 32760 approving the
Company’s December 7, 2012 application for an ILC Program, as modified by the Stipulation
filed February 7, 2013.
II. IRRIGATION LOAD CONTROL PROGRAM
Contract Terms
5. The ILC Program has remained materially the same over the past decade.
Irrigators on Electric Service Schedule 10 who choose to enroll in the ILC Program can earn
cash incentives for curtailing electricity during peak demand periods. The current 10-year
contract term with Enel X is coming to an end. In order to continue administering the ILC
Program to Idaho customers, a new, updated contract with Enel X is needed. Attached hereto
as Confidential Exhibit A is a new contract (“Contract”) with Enel X for the administration of
the ILC Program through 2033. The Contract consists of the following components:
• Master Professional Services Contract Agreement (“MSA”) between
PacifiCorp and Enel X dated February 22, 2022.
• Task Order Release Agreement (“TOA”) between PacifiCorp and Enel X dated
December 20, 2023.
The MSA serves as a general terms agreement between PacifiCorp and Enel X that will apply
to any services provided by Enel X across PacifiCorp’s service territory. Task Order Release
Agreements authorize specific work under the MSA terms and provide detailed scopes of work
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and pricing that pertain to any given project under the MSA. The TOA provided in Confidential
Exhibit A includes the defined services and pricing for the ILC Program. The ILC Program
TOA has an initial 5-year term through 2028, with an option to extend an additional 5 years
through 2033 if agreed to by both parties.
Program Design
6. Enel X works with Rocky Mountain Power customers to enroll irrigation pumps
that best fit the ILC Program and provide the greatest financial incentive to customers. During
the ILC Program season, Enel X provides irrigators with a notice at least two hours prior to
upcoming load control events with an option to opt-out. Enel X’s load control devices shut off
irrigation pumps automatically at the start of a dispatch event and release control of the pumps
at the end of the event, allowing them to restart. Enel X pays irrigators in the fall after the
season has ended based on average available load during program hours, adjusted for the
percentage of events in which customers participated.
Incentive Structure
7. The ILC Program will continue to be a pay-for-performance structure that
compensates irrigators for the average available load, measured in kilowatts (kW), that a pump
can reliably shut-off during program hours, adjusted for event participation. This average
available load per pump will then be multiplied by the applicable incentive rate, according to
Table 1 below. The average load for each pump is measured by the load control devices on
each pump. It is the average energy demand during all program hours (weekdays, 2:00pm
– 9:00pm), excluding days when events are called. A pump’s available load depends on its size
and how often it is running. If a customer chooses to opt-out of a load control event, the
available load is adjusted down by the percent of events in which they elected to opt out, and
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they will receive the Base Incentive Rate as defined in Table 1. If a customer participates in all
mandatory events, as defined in Confidential Exhibit A, they are eligible to receive the Bonus
Incentive Rate as defined in Table 1. Customers participating in mandatory events will also
receive an incentive payment based on the actual load reduced multiplied by the Mandatory
Event Energy Reduction Payment (“ERP”) Rate specified in Table 1.
Table 1 – ILC Program Incentives (Mandatory Season)
Program
Year Incentive *if Customer Participates in Mandatory Event Energy Reduction Payment Rate
2024 $32.50 $39.00
$0.075/kWh

Dispatch Parameters
8. The Company will continue to dispatch mandatory and voluntary events. In
order to be eligible for the bonus incentive rate, participating customers must participate in all
events during the Mandatory Season, based on the criteria in Table 2. Voluntary events are
events that occur outside of the Mandatory Season dispatch parameters. Participating
customers may choose to opt-out of any or all voluntary events with no penalties or reductions
to their financial compensation. For customers who do participate in voluntary events, they
will earn an ERP for each event. The ERP will be equal to the actual load reduced during the
voluntary event multiplied by the voluntary ERP rate of $0.38/kWh.

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Table 2 – ILC Program Dispatch Parameters - Mandatory Season
Dispatch Period Week including June 1 through August 15
Available Dispatch Hours 2:00 PM to 9:00 PM Mountain Time
Maximum Dispatch Hours 52 hours per Mandatory Season
Dispatch Duration
Dispatch Event Frequency

In the event of a system emergency, Rocky Mountain Power may, at its discretion, expand the
dispatch criteria beyond the parameters described herein. Emergency events may be used to
satisfy requirements of the North American Electric Reliability Corporation standard
BAL-002- WECC-2 for Contingency Reserve Obligation, and may be deployed when the
Company is experiencing a qualifying event as defined by the Northwest Power Pool.
Projected Participation and Costs
The ILC Program currently has approximately 137 megawatts (“MW”) of curtailable demand
response and is projected to maintain approximately 137 MW of curtailable demand response
through 2033. Table 3 provides a breakdown of estimated costs for the ILC Program through
2033, and Table 4 provides an estimate of program participation.
Table 3 – Estimated Program Costs by Category
Year Admin and Customer Incentives Utility Admin Total
2024 $1,141,000 $2,794,000 $65,000
2025 $1,170,000 $2,865,000 $65,000
2026 $1,200,000 $2,938,000 $65,000
2027 $1,230,000 $3,012,000 $65,000
2028 $1,262,000 $3,089,000 $65,000
2029 $1,294,000 $3,167,000 $65,000
2030 $1,326,000 $3,247,000 $65,000
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Year Admin and Customer Incentives Utility Admin Total
2031 $1,360,000 $3,330,000 $65,000
2032 $1,394,000 $3,414,000 $65,000
2033 $1,430,000 $3,501,000 $65,000
Customer incentive costs assume all customers from the previous year continue to participate
in the following years, and 80 percent of enrolled capacity receives the bonus payment. Total
costs in Table 3 leverage a net present value calculation, with an assumed discount rate of
6.77 percent.
Table 4 – Estimated Program Participation
Estimated Site Participation Estimated MW
1,050 125 137

Data Tracking and Reporting
The Company currently reports on the ILC Program in its annual Demand Side Management
reporting, due May 1st annually (“DSM Report”). The Company’s DSM Report includes
program descriptions, program performance and major achievements for the ILC Program, as
well as detailed information on called events. Beginning with the Company’s DSM Report for
2022, the Company also started tracking and reporting on the following additional metrics at
the request of Commission Staff:
a) the date and time for each initiated irrigation event; b) the amount of demand saved in megawatts for each event hour; c) the amount of energy saved in megawatt-hours for each event hour;
d) the value of demand saved in each event hour;
e) the program cost for demand saved in each event hour; f) the value and cost of energy saved in each event hour; g) the corresponding market price of energy for each event hour; h) a breakdown of incentives paid to each participant by event; i) any event adjustment for participant opt-outs; and
j) any event adjustments for non-participation.
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The Company will continue to provide this same level of detail for the ILC Program with the
DSM Report. Additionally, the Company is working to gather hourly interval data for called
events, including the timing leading up to and proceeding an event window. This will allow
the analysis of data throughout the duration of an event, which will lend further insight to each
event’s success. The Company may update its reporting of the ILC Program as more granular
data becomes available.
Program Management
9. Changes to the Program over the past 10 years have been minimal. The
Company anticipates minimal changes will be needed going forward. However, in order to
help manage the ILC Program and the TOA Contract with Enel X, the Company may make
periodic adjustments to incentives, dispatch parameters, and other program design elements as
needed to improve the ILC Program and ensure the ILC Program runs as intended and remains
cost effective. To the extent that the Company anticipates there will be a material difference in
total spend over the 10-year period relative to Table 3 above, the Company will notify and
discuss with Commission Staff, and if necessary, submit a new Application with changes for
the Commission to approve.
Changes in Program Design from Previous Contract
10. The Company included increased incentives for customers in the new ILC
Program contract. The new incentive for customers beginning in 2024 will be increased by 30
percent over previous years, with an additional 2.5 percent increase each subsequent year. The
Company believes that maintaining the same incentives that have been offered the past ten
years will cause participation in the ILC Program to decline. The ILC Program has already
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been seeing a general decline in available load reduction as shown in Figure 1 below, largely
due to the following factors:
• Abnormally dry years. Dry years increase average availability as more irrigation
pumping is required compared to an average year, which increases the load the
Company has available to curtail. However, for abnormally dry years, irrigators
may determine it is not financially viable to curtail their load if they see this having
a non-negligible impact on growing patterns. Increased incentives are anticipated
to mitigate this concern (See Figure 2 below for Pocatello, Idaho precipitation over
the last 10 years)

• Inconsistent weather throughout the season. High variability of weather conditions
throughout a season can lead to inconsistent availabilities that are difficult to
forecast. Variability within a year may impact when an irrigation season begins
and ends, and this timing may not align with the timing of the ILC Program.
• Inflation and rising costs of living. With the high level of variability in inflation
over the past few years, the costs of goods and services have increased
significantly. As a result, it may be less lucrative for irrigators to participate in the
ILC Program if incentives are not increased. Irrigators need to weigh the benefits
of being compensated for their participation against downsides such as possible
loss of profit if changing irrigation patterns reduce crop output or increases labor
costs.

The Company believes that the increased incentives will allow the ILC Program to retain its
current enrollment of customers and may encourage other irrigation customers who have
previously unenrolled from the ILC Program to rejoin.
Figure 1 – Maximum Weekly Average Available Load Reduction
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Figure 2 – Total Annual Precipitation - Pocatello, Idaho (www.weather.gov)

11. The Company modified the Contract to allow for a two-hour notification in lieu
of a four-hour notification for called events. The ILC Program also may move to a more real-
time structure in the coming years. The Company intends to maintain a four-hour notice for
the 2024 season, but included the options for two-hour notices and/or more real-time scenarios
to allow flexibility for a faster acting resource. The Company will discuss the change to a two-
hour notice or real-time events with irrigators prior to implementation if it is determined that
this adjustment is necessary for the ILC Program.
III. COST EFFECTIVENESS
12. A cost effectiveness analysis for the ILC Program is attached hereto as
Confidential Exhibit B. The benefits used in the model generally follow guidelines outlined in
the California Public Utility Commission 2016 DR cost effectiveness protocols,1 where
applicable. The avoided cost analysis for demand response resources is also similar to what is
done for energy efficiency in Idaho and relies primarily on outputs from the 2023 IRP. The

1 Demand Response Cost-Effectiveness (ca.gov)
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following benefit streams are used for valuation of demand response benefits for the ILC
Program:
• Avoided generation capacity costs.
• Avoided energy costs.
• Avoided transmission and distribution capacity costs. Additionally, the Company applies the avoided cost benefit streams to account for parameters
specific to the ILC Program, accounting for the following components when assessing the
realization of benefits:
• Load impacts, in MW
• Hours of dispatch
• Availability of dispatch hours (i.e. when an event can be called)
• Duration of events
• Expected availability of load 13. As avoided costs are considered proprietary on load control programs, the cost
effectiveness results are provided below with a “pass” designation, which equates to a benefit
to cost ratio of 1.0 or better. Due to the nature of demand response, and consistent with the cost
effectiveness methodology for other demand response programs, the Participant Cost Test is
not applicable. The ILC Program is expected to be cost effective under the other benefit/cost
tests. Workpapers in support of the cost effectiveness analysis is provided as Confidential
Exhibit C.
Table 5 – Irrigation Load Control Program Cost Effectiveness Benefit/Cost Test Benefit/Cost Ratio
Pass

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IV. COMMUNICATIONS
14. Communications regarding this Application should be addressed to:
Mark Alder Michael Snow 1407 W. North Temple, Suite 330
Salt Lake City, Utah 84116
Telephone: [phone] [phone] Email: [e-mail] [e-mail]

Joseph Dallas 825 NE Multnomah, Suite 2000 Portland, Oregon 97232 Telephone: [phone]
Email: [e-mail]
In addition, the Company respectfully requests that all data requests regarding this matter be
addressed to one or more of the following:
By e-mail (preferred) [e-mail] By regular mail Data Request Response Center PacifiCorp
825 NE Multnomah, Suite 2000
Portland, OR 97232 IV. MODIFIED PROCEDURE
15. The Company believes that consideration of the proposals contained in this
Application do not requires an evidentiary proceeding, and accordingly requests that this
Application be processed under modified procedure pursuant to RP 201-204, which allows for
consideration of these issues by written submissions rather than by an evidentiary hearing. If,
however, the Commission determines that an evidentiary proceeding is required, the Company
stands ready to provide supporting testimony.

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V. CONFIDENTIAL INFORMATION
16. This filing, specifically the exhibits, contain confidential information including
trade secret and other Company confidential information exempt from public review under
Idaho Code §§ 74-104–109 and Idaho Public Utilities Commission’s Rule of Procedure 67.
VI. CONCLUSION
17. WHEREFORE, Rocky Mountain Power respectfully requests the Commission
issue an Order: (1) authorizing that this proceeding be processed under modified procedure,
and (2) approving the continuation of the Irrigation Load Control Program through the new
10-year contract with Enel X as described herein, with an April 1, 2024 effective date.
DATED this 24th Day of January 2024.
Respectfully submitted,

By _______________________________
Joseph M. Dallas Senior Attorney
PacifiCorp
825 NE Multnomah, Suite 2000 Portland, Oregon 97232 Telephone: [phone] Email: [e-mail]

Confidential Exhibit A
THIS EXHIBIT IS CONFIDENTIAL IN ITS
ENTIRETY AND IS PROVIDED UNDER SEPARATE
COVER
Confidential Exhibit B
THIS EXHIBIT IS CONFIDENTIAL IN ITS
ENTIRETY AND IS PROVIDED UNDER SEPARATE
COVER
Confidential Exhibit C
THIS EXHIBIT IS CONFIDENTIAL IN ITS
ENTIRETY AND HAS BEEN PROVIDED IN
EXCEL FORMAT ONLY