20230223Comments(Redacted).pdf

MICHAEL DUVAL
DEPUTYATTORNEY GENERALIDAHOPUBLICUTILITIESCOMMISSION
PO BOX 83720
BOISE,IDAHO 83720-0074 SS:N(208)334-0320
IDAHO BAR NO.11714
Street Address for Express Mail:
11331 W CHINDEN BLVD,BLDG 8,SUITE 201-A
BOISE,ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF ROCKY MOUNTAIN )POWER'S APPLICATION FOR AUTHORITY )CASE NO.PAC-E-22-13TOIMPLEMENTACOMMERCIALAND)INDUSTRIAL DEMAND RESPONSE )REDACTED COMMENTS OFPROGRAM)THE COMMISSION STAFF
STAFF OF the Idaho Public Utilities Commission,by and through its Attorney of
record,Michael Duval,Deputy AttorneyGeneral,submits the followingcomments.
BACKGROUND
On August 25,2022,Rocky Mountain Power,a division of PacifiCorp ("Company")
applied for authorityto implement a Class 1 Commercial and Industrial Demand Response
("CIDR")program.The Company requested that this program be implemented under the
existing Schedule 114 load management flexible tariff within the Demand Side Management
("DSM")portfolio.
On October 20,2022,the Commission issued a Notice of Application,set an intervention
deadline,and suspended the proposed effective date until February 15,2023.Order No.35568.
P4 Production,L.L.C.,an affiliate of Bayer Corporation,and the Idaho IrrigationPumpers
Association,Inc.intervened.
REDACTED STAFF COMMENTS 1 FEBRUARY 23,2023
On December 8,2022,the Commission issued a Notice of Modified Procedure
establishing public comment and Company reply deadlines.Order No.35616.
At the Commission's January 3,2023,Decision Meeting,Staff conveyedto the
Commission that throughdiscovery,the Company provided Staff new data specific to Idaho,
which would take additional time to process.To give Staff and Intervenors adequate time to
review the Idaho-specific data,work with the Company to determine the relevant information
necessary,and make its subsequent recommendation,Staff recommended the Commission (1)
vacate the comment deadlines established in Order No.35616 and issue new comment deadlines;
and (2)modify the suspension of the proposed effective date.The Company and Intervenors
supported modifying the deadlines as proposed by Staff.
On January l 1,2023,the Commission issued Order No.35662,vacating the prior
comment deadlines set in Order No.35616,and further setting new deadlines for Staff and
Intervenor comments by February 23,2023,and Company reply comments by March 9,2023.
The Commission also extended the suspension of the proposed effective date until April 1,2023.
STAFF ANALYSIS
After careful review of the Application,its exhibits,and the Company's response to
multipleproduction requests,Staff believes the design of the CIDR program should be cost
effective if the assumptions and estimates used to justifythe program are accurate.Given this,
Staff recommends the Commission authorize implementation of the program.However,Staff
believes there is a risk that the program may not be cost-effective once fully implemented if
avoided cost estimates are over-estimated or the program may not remain cost-effective due to
changes in the Company's resource mix over time.Because of these risks,Staff makes several
recommendations in setting up the initial program and to monitor and manage the program once
it is implemented,which are detailed in the sections below.Staff has provided the following
sections with its recommendations and justifications:
1.Description of Program Benefits.
2.Cost-Effectiveness of the Program.
3.Development of Avoided Cost.
4.Elements of the Program Design:
a.Maximum Incentive.
REDACTED STAFF COMMENTS 2 FEBRUARY 23,2023
b.Managing Flexible Tariff.
c.Dispatch Parameters.
d.Monitoring and Metrics.
Description of Program Benefits
In general,cost-effective Demand Response ("DR")programs are less costly to operate
than dispatching traditional marginal cost resources needed to meet system load and reliability
requirements.If the Company's proposed Idaho CIDR program is cost-effective,it will likely
provide a similar benefit to all customers within the Company's Idaho service territory.The
CIDR program is unique in that it can provide benefit throughout the year both in traditional DR
called events as well as periods outside of an event.
During called DR events,the proposed Idaho CIDR program would offset the need for
local system demand and energy by way of load reduction,which in turn reduces the need for
energy deliveries into Idaho from other locations on the system.In program hours outside of
called events,the program,by its existence and ability to respond,provides operating reserves to
PacifiCorp's East ("PACE")balancing area.This offsets the need for other PACE resources to
be held as operating reserves for its balancing area.The energy and/or operating reserve
resources that are freed up by the CIDR program can in turn be used to avoid higher cost sources
of supply elsewhere on the Company's system or can be dispatched for off-system sales.
Consideration for locational marginal pricing and transmission losses are also used to identify
the benefit specific to Idaho customers.
Cost-Effectiveness of the Program
In its Application,the Company states that it expects the program to be cost-effectivel
with a benefit-cost ratio greater than 1.In support of its claim,the Company provided
confidential cost-effectiveness calculations in Response to Production Request No.16 and the
Idaho specific avoided cost in Response to Production Request No.26.Staff was able to verify
the supporting calculations and avoided cost inputs.While the program is expected to be cost-
effective under the Company's estimates for participation,incentive payouts,and other program
i The Company states that it considers avoided costs on load control programs,and by extension the cost-effectivenessresults,as proprietary.
REDACTED STAFF COMMENTS 3 FEBRUARY 23,2023
assumptions,Staff recognizes that the program could become cost-ineffective if incentive
payouts are above the value of the avoided cost.
Development of Avoided Cost
Staff recommends the Company continue to update the program's avoided cost using data
derived from its most recent Integrated Resource Plan ("IRP"),which reduces the possibility of
the program becoming cost ineffective.The Company's current calculated avoided cost used for
implementing the CIDR program seems reasonable,but near-term changes in the procurement
and integration of large-scale utilitybatteries into the system cause a reduction in the calculated
avoided cost at the end of the five-year period.2 A change in the avoided cost directly affects the
basis for determining the program's cost-effectiveness.Using the most current IRP forecast data
will in turn provide the most timely and best estimate of the program's future avoided cost,
which will require the Company to periodically adjust incentive levels to maintain the program's
cost-effectiveness.
Staff believes the Company relied on certain program assumptions that could
significantlyshift the value of the avoided cost and the subsequent CIDR program's cost-
effectiveness.The Company used forecast data from its most recent 2021 IRP to develop the
5-year levelized avoided cost.To estimate the levelized avoided cost,the Company considered
program benefits for both called events and for periods when the program provides reserves
without an event being called.3 In valuingthe benefit during called events,the Company
estimates 27.5 percent of the avoided cost is attributed to reduced hourly energy and capacity
amounts that occur through load reduction.The Company expects the program to dispatch
approximately event hours each year,which is less than ercent of the total hours of the
year.During the remaining hours outside called events,the Company values the program using
hourly data categorized as regulation reserves.The Company defined the regulation reserve
price as follows:
2 Company Response to Production Request No.53'The Real-Time dispatch option provides frequency response reserves (Company Response to Production RequestNo.2)and the Advanced Notice dispatch option provides resources for Contingency Reserve Obligations (Company
Response to Production Request No.3).
REDACTED STAFF COMMENTS 4 FEBRUARY 23,2023
The regulation reserve price represents the opportunity cost of holding back the associateddispatchableresources.When additional regulation reserve resources like DR are madeavailable,relatively low-cost generators are released from holding reserves and cangeneratetoserveload,reducing the need for more expensive sources of supply,or cansupportwholesaleswhichreducesrevenuerequirement.The net benefit from either of
these outcomes is reflected in the regulation reserve price.Specific to the proposed DRprogram,by holding more of the "East 5 Regulation"product for the PacifiCorp East(PACE)BAA4,other resources in the east BAA are relieved of that obligation and can bedeployedinmorebeneficialuses.
Company Response to Staff Production Request No.35(c).
Although less valuable on an hourly basis,the shear amount of hours contributes
significantlyto the remaining 72.5 percent of the avoided cost valuation.Staff believes to fully
understand the program's benefit and ensure the program remains cost-effective,the Company
should be required to submit CIDR program performance informationfrom the prior year.This
annual reporting should continue until the program becomes more established and the program
shows that it maintains cost-effectiveness over time throughits DSM prudence filings.
Elements of the Program Design
Maximum Incentive
Staff believes the Company should limit the Maximum Incentive amount to a value
supported by the 5-year levelized avoided cost."In setting the initial level for participant
incentive,the Company should consider the following:
1.Maintain an incentive amount necessary to retain continued participation in the program
over the long term;
2.Offer an incentive amount adequate to encourage new participants into the program;and
3.Limit the incentive amount to a level that keeps the program cost-effective as avoided
cost fluctuate.
In its Application,the Company provides the annual "maximum incentive up-to"amount
of $l25/kW for participation in either the Real-Time Option or Advanced Notice Option;and
4 Balancing Authority Area ("BAA")'The Maximum Incentive is referenced as an "up to"amount referenced from Table 3 of the Application.TheCompany's referenced 5-year levelized avoided cost of used as the basis tosupportcost-effectiveness calculation is referenced from the Company Response to Production Request 26 -[FileName]Attach IPUC26 CONF;[Tab]C&I Results;[Cell]Bl6.
REDACTED STAFF COMMENTS 5 FEBRUARY 23,2023
$190/kW for participation in both options.The Company states that these values are
"determined to be cost-effective based on the assumptions noted in Confidential Exhibit C."
Response to Staff Production Request No.12 (a).Considering these maximum incentives,the
Company proposed initial incentive offerings of $100/kW and $175/kW for participation in one
or both dispatch options,respectively.These maximum incentives and initial offerings are the
same amounts contained in the existing Utah program and are not updated using Idaho specific
values.Staff is concerned that the methodology the Company used to reach their proposed
maximum and initial incentives are not well supported,do not encourage a cost-effective
program,and will not provide stable incentives to customers.
In the Company's workpapers provided in Response to Production Request No.26,an
Idaho specific,5-year levelized avoided cost value is calculated at .This value is
much less than the proposed annual maximum incentive of $190/kW and the proposed initial
annual incentive offering of $175/kW for participation in both dispatch options.The Company
explains that the capacity factor included in the actual incentive calculation will reduce customer
payout according to the availabilityof curtailable load during the year.Because the Company
does not expect 100%availability from all customers,the outstanding incentive amount can be
used to increase the maximum incentive and by extension initial incentive offerings,above what
is supported by the avoided cost.While this method would encourage participation through
higher incentives,it also runs a significant risk of overcompensatingcustomers if a customer
realizes a higher capacity factor.Staff believes,the Company was unable to provide adequate
support for offering incentives above what is supported by the avoided cost.By inflating the
maximum incentives above what is supported by the avoided cost,the Company has set an
unreasonable standard and created a basis for the program that would not be cost-effective,if
fully realized.
As a general principle,the maximum amount of program incentives plus non-incentive6
costs need to be less than the program avoided costs to be cost-effective;however,at an
individual participant level,the maximum incentive may be higher due to varyingincentive
levels for participants.Therefore,Staff recommends that the maximum incentive for
participation in one or both dispatch options be set at the 5-year levelized avoided costs of
6 Non-incentiveexpenses include program administration,utility administration,and marketing costs.The Companyestimatesthesecostsbetween$97,500 and $142,250 depending on the maturity of the program.
REDACTED STAFF COMMENTS 6 FEBRUARY 23,2023
calculated in the workpapers provided in Company Response to Production
Request No.26.This directly translates to an annual maximum incentive amount of
.By using avoided costs as a maximum incentive "up to"limit for individual
participants,the program should remain cost-effective at a program level.The maximum
incentive assumes a 100%capacity factor for every participant which is unlikely to occur.When
calculating the cost-effectiveness of the program,it considers individualcustomer capacity
factors,varying incentive offerings by participant,and all non-incentive expenses.When
customers are signed up on a lower initial incentive or have lower capacity factors for a given
year,this would ensure the program remains cost-effective.For example,if a customer is signed
up at a maximum incentive of and has an average capacity factor of 75%,the customer
would only receive incentive payments of .Staff believes that this conservative
maximum incentive will help ensure that the program remains cost-effective when including
non-incentive expenses.
Finally,Staff cautions the Company against setting initial incentive offerings too high.
Staff notes that the avoided cost forecasts provided in Company Response to Production Request
No.26 are predicted to decrease significantlyacross the next several years.For example,when
breaking the 20-year avoided cost forecast into consecutive 5-year blocks,this produces 5-year
levelized avoided cost of for the 2027-2031 period and for the 2032-2036
period.While these forecasted avoided costs are subject to change when updated in each IRP
filing,initial incentive offerings near the maximum incentive may require the Company to make
changes to customer incentives when the 5-year avoided cost drops below current offerings.
Considering the forecasted decreases in cost-effectiveness,Staff is concerned that the Company
will need to make frequent reductions to customer incentives to remain cost-effective.This
could be perceived by participants as a take away and result in customer dissatisfaction and
reduce participation in the program.Therefore,Staff recommends the Company set initial
incentive offerings to customers that will provide stability in their incentive rate over multiple
years as the Company's avoided cost declines.When proposing initial incentives based off the
maximum incentive "up to"recommended above and in all future Company filings,the
Company should be able to explain how the incentives will promote required participation while
balancing the risk of future reductions in incentive rates.
REDACTED STAFF COMMENTS 7 FEBRUARY 23,2023
Managing Flexible Tariff
Staff believes the Company should be allowed to adjust the program incentive within the
flexible tariff on an annual basis.In its Application,the Company requests that the program is
implemented under the existing Schedule 114 load management flexible tariff.If implemented
in this way,the flexible tariff would allow the Company to make adjustments to program
incentives and other parameters through Rocky Mountain Power's website,with hard copies
provided to customers upon request,while allowingfor adequate Staff input.Staff agrees that a
flexible tariff will allow the Company to make swift adjustments when necessary and reduce risk
to the proposed program.As stated in the previous section,Staff is also concerned that frequent
fluctuations in incentives and parameters may create uncertainty for customers and reduce
participation.Staff recommends the Company be allowed to adjust the program incentive within
the flexible tariff on an annual basis.Yearly changes will provide ample data to identifytrends
in program performance metrics such as participation rates and cost-effectiveness.Additionally,
annual updates would align more closely with regularly occurring annual DSM reports,DSM
prudency filings,and IRP filings.
Dispatch Parameters
Staff recommends the Company submit an updated Exhibit B in a compliance filing with
corrected tables that clearly show the dispatch parameters of each option in the proposed
WattSmart Business DR program.During its analysis,Staff discovered different dispatch
parameters in Table 6 of the Application and in the proposed tariff shown in Exhibit B.In its
Response to Staff Production Request No.33,the Company clarified that the parameters shown
in Exhibit B are the combined parameters of the Real-Time and Advanced Notice options.Staff
has provided a comparison of the parameters from the two tables as shown in Table 1 below.
REDACTED STAFF COMMENTS 8 FEBRUARY 23,2023
Table No.1:Comparison of Dispatch Parameters Shown in Application Table 6 and in
Exhibit B
As shown in ApplicationTable 6
Dispatch Parameter Real-Time Program Advanced Notice Program
Dispatch Period January 1through December 31 January 1through December31
Available Dispatch Hours 12:00am to 11:59pm Mountain Time 12:00am to 11:59pm Mountain Time
Maximum Dispatch Hours 5 hours 60 hours
Maximum Events per
Year 50 events per year 25 events per year
Dispatch Days Monday-Sunday Monday-Sunday
Dispatch Duration 3 minutes to 7 minutes 5 minutes to 4 hours per day
As Shown in Exhibit B
Dispatch Dispatch Available Maximum Dispatch Dispatch DispatchParameterPeriodDispatchHoursHours/events per year Days Duration
WattSmart January 1 12:00am to Events limited
Business Demand through 11:59pm Monday-to 4 hours per
Response December 31 Mountain Time 65 hours /75 events Sunday day
Staff believes it is inappropriate to combine the dispatch parameters of the Real-Time and
Advanced Notice options in the proposed tariff.It is clear from the different dispatch parameters
presented in Table 6 of the Application that the two options are intended for different functions
and should not be combined.As proposed,the Company would be providing inaccurate dispatch
parameters to potential customers relative to their subscribed program.
Additionally,the Company states that the value of the Real-Time option's primary use
for frequency response overlaps with the value of spinning reserves in the avoided cost model
and is not directly known.Company Response to Staff Production Request No.26.Staff
supports including the incentive because it provides a valuable service for the Company and can
be used for other grid management functions.However,Staff recommends that the Company
directly identifythe value of frequency response.The Company should describe its efforts to
identify the value of frequency response in their annual DSM reports,IRP processes,and offer
an appropriate incentive once a value has been identified and vetted by Staff.
REDACTED STAFF COMMENTS 9 FEBRUARY 23,2023
Monitoring and Metrics
Staff is encouraged by the opportunityof the CIDR program proposal.A successful
program can help to activelymanage load on the Idaho system and provide a more resilient grid.
Consistent with all other Company DSM programs,Staff recommends the Company submit
updates on the Wattsmart DR program in its DSM annual reports and request a prudence
determination and potential recovery of CIDR program expenses as part of the Company's DSM
prudence filing.
In addition to all reporting items required in a DSM annual report,the Wattsmart
Business CIDR program section should include the followingperformance metrics separated by
the Real-Time and Advanced Notice dispatch options:
(1)For each program event called during the year:
a.the date,time,duration,and reason for the called event (i.e.frequency
response,peak load reduction,contingent reserve,regulation reserve,or due to
the economics);
b.the hourly aggregate amount of DR called,and separately each participant's
called amount;
c.both the hourly aggregate and individual participant amounts of DR received
during the event;
d.the program's designated hourly capacity factor both in aggregate and by
individual participant;
e.both the hourlyaggregate and individual participant amounts of DR received
during the called event;
f.the value of energy for each hour during the event;
g.the hourly value of capacity for each hour during the event;
h.separately the value of reserve types for each hour during events;
i.the value of spinning reserve offset by load reduction for each hour of the
event;
j.details of any participant opt outs;
(2)For all other hours outside of called events during the year:
a.the dates,and times when the Company used incremental contingent reserves
or regulation from the program to provide benefit to the system;
REDACTED STAFF COMMENTS 10 FEBRUARY 23,2023
b.individuallythe value of contingent and regulation reserves for each hour the
program provided benefit to the system;
c.the hourly value to the system where a resource held in reserve was
subsequently allowed to provide generationinto the market due to the
programs ability to provide contingent reserves;
(3)All other trackable metrics relevant to supporting the programs performance and cost-
effectiveness
STAFF RECOMMENDATION
Staff recommends that the Commission authorize the implementation of the CIDR
program conditioned on the following:
1.The Company limit the maximum incentive for participation in one or both dispatch
options at the current levelized 5-year avoided cost.
2.The Company regularlyupdate the levelized 5-year avoided cost for determining the
maximum incentive using the Company's most recent filed IRP.
3.The Company be allowed to adjust the program incentive within the flexible tariff on
an annual basis.
4.The Company consider the followingin setting the initial incentive level for program
participation:
a.Maintain an incentive level amount necessary to retain continued participation
within the program over time.
b.Offer an incentive level amount adequate to encourage new participants into the
program.
c.Limit the incentive amount to a level that keeps the program cost-effective.
5.The Company submit in a compliance filing a corrected Exhibit B to the Application
that shows corrected tables that clearly reflect the dispatch parameters of each
dispatch option in the proposed WattSmart Business DR program.
6.The Company submit updates to the Wattsmart DR program in its DSM annual
reports and request a prudency determination and potential recovery of CIDR
program expenses as part of the Company's DSM prudency filing.
REDACTED STAFF COMMENTS 11 FEBRUARY 23,2023
7.The Company submit annual ex post monitoring and trackable metrics that support
the program's performance and cost-effectiveness as detailed above.
Respectfully submitted this day of February 2023.
Michael Duval
Deputy Attorney General
Technical Staff:Rick Keller
Jason Talford
Laura Conilogue
i:umisc/comments/pace22.13mdrkcomments
REDACTED STAFF COMMENTS 12 FEBRUARY 23,2023
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 23RD DAY OF FEBRUARY 2023,SERVED THE FOREGOING REDACTED COMMENTS OF THE COMMISSIONSTAFF,IN CASE NO.PAC-E-22-13,BY E-MAILING A COPY THEREOF,TO THEFOLLOWING:
BRUBAKER &ASSOCIATES THOMAS J.BUDGEBRIANC.COLLINS RACINE,OLSON PLLPGREGMEYER201E.CENTER
16690 SWINGLEY RIDGE RD.,#140 PO BOX 1391
CHESTERFIELD,MO 63017 POCATELLO,ID 83204-1391E-MAIL [e-mail] E-MAIL:[e-mail]
[e-mail] (Redacted Comments)(Redacted Comments)
ERIC L.OLSEN
ECHO HAWK &OLSEN PLLC
505 PERSHING AVE.,SUITE 100
PO BOX 6119
POCATELLO,ID 83205
E-MAIL:[e-mail]
(Redacted Comments)
LANCE KAUFMAN,PH.D.
2623 NW BLUEBELL PLACE
CORVALLIS,OR 97330
E-MAIL:[e-mail]
(Redacted Comments)
SECRËTARf '
CERTIFICATE OF SERVICE