20231012Comments of the Commission Staff.pdf

CHRIS BURDIN E Ü
DEPUTY ATTORNEY GENERAL ;p ()IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720 SUC
BOISE,IDAHO 83720-0074 MF SS N
[phone]
IDAHO BAR NO.9810
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 IDAHO POWER )COMPANY'S APPLICATION FOR )CASE NO.IPC-E-23-14
AUTHORITY TO IMPLEMENT CHANGES )TO THE COMPENSATION STRUCTURE )APPLICABLE TO CUSTOMER ON-SITE )COMMENTS OF THE
GENERATION UNDER SCHEDULES 6,8,)COMMISSION STAFF
AND 84 AND TO ESTABLISH AN EXPORT )CREDIT RATE
COMMISSION STAFF ("STAFF")OF the Idaho Public Utilities Commission
("Commission"),by and through its Attorney of record,Chris Burdin,Deputy Attorney General,
submits the followingcomments.
BACKGROUND
On July 27,2017,in Case No.IPC-E-17-13,Idaho Power Company ("Company")filed
an application with the Commission for authorityto establish new schedules for residential and
small general service customers with on-site generation.In that case,the Commission separated
on-site generation customers as distinct rate classes;recognized the need to address the costs,
benefits,rates,rate design,and compensation of on-site generation customers;reasoned that it is
unfair for on-site generationcustomers to be able to avoid paying their share of fixed costs;and
ordered the Company to prepare and file a credible and fair study on the costs and benefits of on-
STAFF COMMENTS 1 OCTOBER 12,2023
site generationto the Company's system,as well as proper rates and rate design,transitional
rates,and related issues of compensation for net excess energy provided as a resource to the
Company.Order No.34046.
On December 20,2019,in Case No.IPC-E-18-15,the Commission denied a settlement
proposed by the Company,Staff and intervenors.In its reasoning,the Commission reiterated
that the Company must submit a comprehensive study before proposing changes to the Net
Energy Metering ("NEM")programs.I The Commission directed that the study:(1)must use the
most current data possible and must be readily available to the public,and in the Commission's
decision-making record;(2)must be designed in coordination with the parties and the public,and
the Commission will determine the final scope of the study;and (3)the study must be written so
it is understandable to an average customer,but its analysis must be able to withstand expert
scrutiny.Order No.34509 at 9.Additionally,the Commission established Grandfather Status
for customer generators with existing on-site generationsystems and those that complete their
systems within one year of the service date of Order No.34509.Id.at 14.
On June 28,2021,in Case No.IPC-E-21-21,the Company filed an application with the
Commission to initiate a multi-phase process for the study of costs,benefits,and compensation
of net excess energy associated with on-site customer generation,in its application the Company
included a proposed study scope.In that case,the Commission received public comments and
multiplerounds of comments from the Company,Staff,and intervening parties on different
elements to be included in the study scope.Based on the input of the diverse parties,the
Commission provided additional direction and specific requirements for each element to be
included in the study.Order No.35284.
On June 30,2022,the Company submitted an application with the Commission to
Complete the Study Review Phase of the Comprehensive Study of Costs and Benefits of On-Site
Customer Generationand for Authority to Implement Changes to Schedules 6,8,and 84.
Included in the application was the completed Value of Distributed Energy Resources
("VODER")study and its supporting appendices.In that case,the Commission found that the
Company had completed a fair and credible study in accordance with previous orders and
i NEM is the current compensation structure where customer-generators receive a kWh credit for excess energy
deliveredto the grid.The kWh credit can be applied to offset energy consumption within the current billing cycle or
future billing cycles.NEM requires a single bi-directionalmeter read for the billing period.
STAFF COMMENTS 2 OCTOBER 12,2023
acknowledged that the Company filed its completed VODER study.Order No.35631.The
Commission then directed the Company to file a new case requesting changes to its NEM
program.Id.
On May 1,2023,the Company filed an application ("Application")with the Commission
proposing changes to the Company's on-site and self-generation tariffs.The Company requests
that the Commission authorize:(1)real-time net billing with an avoided cost-based financial
credit rate for exported energy;(2)a methodology for determining annual updates to the Export
Credit Rate ("ECR");(3)a modified project eligibilitycap for Commercial,Industrial,and
Irrigation("CI&I")customers;(4)related changes to the accounting for and transferability of
excess net energy financial credits,and (5)updated tariff schedules necessary to administer the
modified on-site generation offering.The Company requests an effective date of January 1,
2024.
The Company represents that its recommendations are guided by the following
objectives:(1)recommend a compensation structure that will accurately measure a customer-
generator's use of the system -both in recording exported energy and usage;(2)apply methods
that will result in a fair and accurate valuation of customers'exported energy;(3)implement a
repeatable method for updating the ECR that will ensure timely recognition of changing
conditions on Idaho Power's system and the broader power markets which may warrant changes
to the ECR;(4)balance accuracy with customer understandability.Application at 15-16.
The Company represents that the proposed changes to the on-site generationservice
offerings would only apply to non-legacy customers taking service under Schedules 6,8,and 84.
Customers with legacy systems will continue to take service under the rules of monthlyNEM
until legacy status terminates on December 20,2045,also known as Grandfather Status.Id.at
16.
The Company is proposing a real-time net billing with an avoided cost-based financial
credit rate for exported energy.The Company states that the customer-generator will first
consume any of their generationon-site,and any generationthey are not consuming will be
metered and exported to the grid at a defined ECR.The Company represents that customers will
generate financial credit,based on the product of measured exportedenergy and the ECR,which
can be monetized to offset current or future charges associated with utility provided service.Id.
at 17-18.
STAFF COMMENTS 3 OCTOBER 12,2023
The Company is proposing a seasonal and time variant ECR to compensate for energy
and other elements associated with avoided capacity,line losses,and integration costs.
The proposed On-Peak season and time variance is between June 15 and September 15,3pm to
11pm,excluding Sundays and holidays,with all other hours considered Off-Peak.The Company
valued its ECR using a series of costs avoided or deferred by the Company through the existence
of on-site generation exports on the Company's system.These avoided costs include energy,
generation capacity,transmission and distribution,and line losses offset by an integration cost.
The Company's proposal extends only to non-legacy systems.Id.at 19-20."Legacy"systems
for Schedules 6 and 8 are systems that were installed or purchased by December 20,2019,and
that meet other eligibilityrequirements.Order Nos.34509 and 34546."Legacy"systems for
Schedule 84 are systems that were installed or purchased by December 1,2020,and that meet
other eligibilityrequirements.Order No.34854.
The Company is also seeking a change in how the project eligibilitycap is defined for
Schedule 84 customers.The Company proposes that,if the net billingcompensation structure is
approved,the project eligibilitycap be set at the greater of 100 kW or 100%of demand at the
service point for Schedule 84 customers.If the net billingcompensation structure is not
approved,the Company does not propose modifying the existing project eligibilitycap,because
it serves to mitigate cost-shifting under the current net metering compensation structure.Id.at
20-21.The Company does not propose any modification to the 25kW project eligibilitycap for
Schedule 6 and Schedule 8 customers.For Schedule 6,8,and 84,the Company proposes that
energy storage devices are not used to calculate the nameplate capacity of on-site generation
facilities for Schedule 6,Schedule 8,and Schedule 84 customers.
The Company represents that for purposes of administering the cap,the Company
proposes using the maximum billingdemand from the last 12 months,measured when the
customer generation application is submitted.Id.at 22.The Company states that for irrigation
customers without a full in-season billing history,a conversion factor related to the horsepower
of the customers'pump(s)at the service point would determine the maximum demand.Id.
The Company represents that for customers with non-legacy systems,the Company
proposes to treat ECR expenditures as a Net Power Supply Expense ("NPSE")subject to 100%
recovery through the Company's Power Cost Adjustment ("PCA").Id.at 23-24.
STAFF COMMENTS 4 OCTOBER 12,2023
The Company proposes that financial credits may offset all billing components of the bill,
not justthe energy-relatedportion of a customer bill.Id.at 24.
The Company represents that customers with non-legacy systems will be able to transfer
financial credits to another account held in their name for their own usage,which will be
administered similar to the Company's current NEM service offering for customers transferring
kilowatt hour ("kWh")credits;however,the Company is not proposing to change the
transferability of kWh credits for legacy customers.Id.
The Company proposes that accumulated kWh credits held at service points with non-
legacy systems will be converted to financial credits one year after the effective date of a
Commission-authorized change in compensation structure.Id.at 25.
The Company represents it will issue a news release and will directlynotify its customers
of the Application with a bill insert included with their next billing cycle.Id.at 26-27.The
Company will also send direct-mail letters to all existing and pending on-site generation
customers and will have information regarding its proposals on its website.Id.at 27.
STAFF ANALYSIS
Based on the analysis presented in the sections below,Staff recommends that the
Commission issue an order to:
1.Implement Staffs proposals for a real-time net billing with an avoided cost based,
seasonal,time-variant,ECR,with the followingrecommendations:
a.Adjust the On-Peak season to align with the summer season proposed in the GRC.
Direct that updates to the season be part of future general rate case filings;
b.Accept the On-Peak hours,as proposed by the Company,but direct that if future
IRP analysis indicates a need to update the hours of highest risk,the Company
should file a separate docket;
c.Distribute the avoided energy value in alignment with the summer and non-
summer seasons,as determined in the GRC;
d.Use the most current levelized capacity cost for the least-cost dispatchable
resource from the 2023 IRP;
e.Use afive-year rollingaverage of the ELCC percentage to determine the avoided
capacity value;
STAFF COMMENTS 5 OCTOBER 12,2023
f.Calculate the ELCC and avoided capacity values without the line loss gross up,
and subsequently apply the line loss gross up to that result;
g.Include all customer exports in the calculation of each year's ELCC;
h.Use the industry-typicalline loss calculations.Apply the annual energy line
losses to the energy value,and the peak hour line losses to the capacity value.
2.Direct the Company to update all proposed components of the ECR except the hours of
highest risk in an annual filing beginning April 1,2025.
3.Direct the Company to update the hours of highest risk in a separate filing on an as-
needed basis.
4.Maintain the current Schedule 6 and Schedule 8 eligibilitycaps but monitor when the cap
becomes limitingand consider changes to the cap if warranted.
5.Approve the proposed eligibilitycap for Schedule 84 customers:the greater of 100 kW
and 100%of demand and:
a.Incorporate into Schedule 84 the Company's proposed methods used to determine
a customer's demand relative to the Schedule 84 cap.
b.Direct the Company to play a more active role to verify the need for a
professional engineerto conduct an analysis to determine a new customer's
demand requirements.
c.Direct that the cost of such analysis should be charged to the on-site generation
customer.
d.Incorporate into Schedule 84 the description of the Company's proposed
treatment when a customer's demand changes;and
e.Clarify in Schedule 84 that an expanded system is still subject to the project
eligibilitycap,which is the greater of 100 kW or 100%of demand at the service
point.
6.Incorporate the Company's additional proposed interconnection requirements in Schedule
68 due to the increase of the project eligibilitycap for Schedule 84.
7.Approve the Company's proposal to exclude energy storage and only include the
nameplate capacity of generationto enforce the eligibilitycap for Schedules 6,8,and 84;
and to require the customer to pay all upfront and ongoing costs of system upgrades
through a surcharge,if upgrades are needed.
STAFF COMMENTS 6 OCTOBER 12,2023
8.Approve the Company's request to recover ECR expenditures as a net power supply
expense subject to 100%recovery through the PCA.
9.Approve the Company's proposals on the use and transferability of financial credits.
10.Approve the Company's proposal to convert accumulated kWh credits to financial credits
using a blended average retail energy rate on December 31,2024,and:
a.Direct the Company to notify each non-legacy customer that has excess kWh credits
as of December 31,2024 of how their excess credits will be converted,at what rate,
and how it will be displayed on their next bill.
11.Direct the Company to transfer or refund any accumulated financial credits in the event a
customer relocates or discontinues service.
12.Authorize the integration rates from the 2020 Variable Energy Resource ("VER")study
as proposed for purposes of the ECR rates in this filing,and:
a.Direct the Company file an update to Schedule 87 rates and integration costs from
the 2020 VER study for Commission approval to be used in future ratemaking
that requires it,includingupdates to Clean Energy Your Way ("CEYW")and
ECR-related rates.
b.Direct the Company to file all future VER studies and integration costs for
Commission authorization,if integration cost have materially changed from those
authorized.
13.Direct the Company to adjust the language of Tariff Schedules 6,8,and 84 according to
all recommendations presented above in a compliance filing.
Case History&Introduction
As a basis for its analysis,Staff used established Commission language on the necessity
of an updated rate for the Company's on-site generationprograms.Order No.34046 established
the need to create the rate classes based on evidence of cost-shifting and the increasing feasibility
and penetration of on-site generationtechnology;and established the need to study the costs,
benefits,proper rates and rate design,and other issues.
On the topic of cost shifting,the Commission stated that:"Our analysis of the history of
the Company's on-site generationprogram reveals an unfairness in how current and future on-
site generation customers avoid fixed costs.The ability these customers have to 'net out'or net
STAFF COMMENTS 7 OCTOBER 12,2023
to zero their electricity use causes them to underpay their share of the Company's fixed costs to
serve customers,and this inequity will only increase as more customers choose on-site
generation."Order No.34046 at 16.The stated ability of customers to net out their fixed costs
is a product of the technological limitation of bi-directional meters common in place at the time
of when the Company began offering NEM in 1983.Those meters only had a single channel
meaning it would simply spin backwards when a customer exported power,banking the export
until the next unit of consumption rolled the meter forward.This limitation meant that a
customer could potentiallyuse a kWh exportedduring the day to offset load during the night.
Since the time of the original NEM offering,the Company has installed Advance Metering
Infrastructure ("AMI")meters that are capable of tracking imports and exports as separate
channels.
When paired with the Company's rate structure,the current NEM leads to the on-site
generationcustomers not paying their share of associated fixed costs.Under the Company's
current rates,energy rates have fixed costs embedded into them.Any time an on-site generation
customer uses a banked export to offset consumption the Company is not recovering the fixed or
variable costs incurred to serve that customer,thus driving a difference between the actual and
expected recovery for the Company.The difference between the fixed and variable costs
incurred and not recovered is reflected in the Fixed Cost Adjustment ("FCA")2 and PCA 3
mechanisms.In both mechanisms,the difference is captured and passed on to all customers in
the form of an increased surcharge to the PCA and FCA;thus,shifting costs to non-generating
customers.
In Case No.IPC-E-17-13,Staff and intervenors attempted to quantifythe subsidy created
from this situation.The Commission stated that "we need not quantifya cost shift in either
direction to make our decision."Id.at 17.From review of the Company's current rate structure
and consistent with the Commission language,Staff believes it is necessary to change the
Company's current net energy credit offering to a financial based ECR.If a change does not
occur,the increasing penetration of on-site generation will in turn increase the subsidy to on-site
2 The FCA accounts for the difference between the expected recovery of the fixed cost components embedded in
variable rates and the actual amount that the Company received.The FCA is calculated using the difference
between actual collections and an approved recovery amount based on the most recent rate case.
3 The PCA is a mechanism that the Company uses to account for the variablecosts incurred to supply power for its
customers.At a high level,the PCA is calculated using the differencebetween the actual NPSE and the revenue
collection based on expected usage.
STAFF COMMENTS 8 OCTOBER 12,2023
generation customers.In 2017,the Company identified 1,468 active and pending on-site
generators on its system.IPC-E-17-13,application at 6.As of June 2023,this number has
grown to 17,098 systems.See Response to Production Request No.21.As federal policy,
environmental considerations,and economic drivers increase the implementation of on-site
generation systems,it remains important to address the identified cost shift to protect all
customers by moving forward with an ECR from the current one-to-one energy credit offering
for non-legacy customer in Schedule 6,8,and 84.
Staff Proposed ECR
Staff believes that,in general,the Company's proposals are reasonable and well
supported by the extensive case history.However,Staff disagrees with some of the Company's
proposals,and Staff has prepared an alternate proposal recommending changes to the summer
season,allocation of energy value,and line losses.A summary of Staff's proposed ECR design
and comparison to the Company's proposed ECR is presented in Table 1 below.
Table 1 -Comparison of Company and Staffproposed ECR's
ECR by Component (cents/kWh)Staff Proposed Company Proposed
Season ECR Season ECR
Energy Summer 5.66 ¢On-Peak 8.59 ¢
Includingintegration and losses Non-Summer 4.84 ¢Off-Peak 4.91 ¢
Generation Capacity On-Peak 9.18 ¢On-Peak 11.59 ¢
Off-Peak 0.00 ¢Off-Peak 0.00 ¢
Transmission &Distribution Capacity On-Peak 0.18 ¢On-Peak 0.25 ¢
Off-Peak 0.00 ¢Off-Peak 0.00 ¢
Total Summer On-Peak 15.06 ¢On-Peak 20.42 ¢
Summer Off-Peak 5.66 ¢Off-Peak 4.91 ¢
Non-Summer 4.84 ¢
For its analysis of each of the ECR components,Staff considered the criteria identified in
Case No.IPC-E-22-22:understandability,transparency,accuracy,and stability.Although
understandability,transparency,and stability are criteria that are uniquelyimportant to customer
STAFF COMMENTS 9 OCTOBER 12,2023
generators,the accuracy of the ECR is not only important to customer generators so they receive
an accurate value for their exports,but also important to all other ratepayers who consume and
are being charged for customer-generator's exports.
Staff utilized the principles of avoided cost to determine the accuracy of avoided cost
values in the ECR and to identify the components that should be included.Using avoided cost to
accurately determine the ECR will ensure that customers who consume exported power from
customer generators are "indifferent"as to whether the Company receives its power from the
Company's existing resources or from customer generators.4
Finally,Staff evaluated the Companies analysis for differentiating rates based on the
value of exports using the levels of reliability risk in the Company's system during different time
periods.
Measurement Interval
The current NEM structure uses a monthlynetting interval which allows the exporting
customer to "bank"exports,in the form of energy credits,for use during hours when the
customer was a net consumer.This allows a customer to use any excess kWh credits from
exports to offset their consumption when they are not exporting.
For the measurement interval of the ECR,Staff considered both a real-time,and hourly,
netting interval consistent with Commission Order No.35631.Staff did not consider any
interval larger than hourly (i.e.,daily,weekly,monthly,etc)because the longer the interval,the
less accurate the measurement becomes.
Real-TimeInterval
Based on its analysis of the measurement interval,Staff believes that a real-time interval
presents many advantages in terms of accuracy,understandability,and malleabilityof the ECR.
A real-time or instantaneous measurement interval takes advantage of the AMI meter's
4 The Commission has used avoided cost principles to evaluate and set rates for resources that providepower and
benefits to the Company's system for Public Utilities Regulatory Power Act ("PURPA")projects,Demand-Side
Management ("DSM")resources,and special-contract customer-generation projects through the Company's Clean
Energy Your Way program.The basis of avoided cost is well documented in Indep.Energy Producers Ass'n,Inc.v.
Cal.Pub.Utils.Comm'n,36 F.3d 848,858 (9th Cir.1994)("If purchase rates are set at the utility's avoided cost,
consumers are not forced to subsidize QFs because they are paying the same amount they wouldhave paid if the
utility had generated energy itselfor purchased energy elsewhere.")
STAFF COMMENTS 10 OCTOBER 12,2023
capability to track imports and exports separately.Under this measurement interval,energy that
customer generators are exporting to the system is tracked through the meter in the same way as
consumption.Because the export is counted at the moment it is exported,a real-time interval is
the most accurate interval available,limited only by how often the Company collects data and
aggregates it for analysis.In its Response to Production Request No.6,the Company stated that
under the proposed real-time measurement interval,data would be pulled from the AMI meter on
an hourly basis.Althoughthe data is gathered on an hourlybasis,the data is still based on
energy counted at the moment of export.
By using the proposed real-time measurement interval,exports would be tracked in a
manner consistent with imported power.Imports and exports would each have their own meter
channel,using data collected on the same time schedule and with each having its own associated
rate.Staff believes that having consistency between exports and billing will increase customer
understandability and transparency.
Under a real-time interval,the Company and customer generators would have both the
import and export data for every hour.6 This interval matches the hourlyresolution of the
proposed ELAP market prices and the granularityof other Company analysis and programs such
as TOU consumption billing.Staff believes aligning the measurement interval with the
resolution of other data will increase the potential options for future optional rate structures.
Staff recognizes that implementing a real-time measurement interval will likelyincrease
the bills for on-site generation customers;however,Staff is confident that this impact will be
caused strictly from increasing the accuracy of tracking exports and will reduce cost shiftingto
non-customer generators.
HourlyNettingInterval
Based on its analysis of the measurement interval,Staff believes that a net hourly interval
is less accurate,does not present real benefits,and is less understandable than a real-time
interval.Similar to the current monthlynetting,an hourly netting interval allows a customer to
bank and consume exported energy within the netting period (i.e.,hourly).By shortening the
netting interval from a monthlyinterval to a more granular hourly interval,the ability to offset
5 Customer generators will be able to access their imports and exports for their meter through their My AccountinformationthatisavailabletoacustomerthroughtheCompany's website or app.
STAFF COMMENTS 11 OCTOBER 12,2023
imports is reduced.The Company demonstrates this in the VODER study by showing that the
inaccuracy of an hourly net billing structure yields a quantifiable difference when compared to a
real-time net billingstructure.See October VODER study,p.21,Figure 3.5-3.16.
From the perspective of a customer-generator,an hourly netting interval has the effect of
slightly extending the one-to-one kWh offset benefit that the customer experiences behind the
meter as generation offsets load.However,this "benefit"is due to the inaccuracy of the netting
interval and is not associated with an actual reduction in consumption.For all other customers
on the Company's system,the inaccuracy of the netting translates to an expense paid to exporters
for energy that is not actuallyprovided to the Company's system.
Regardless of using real-time or hourly netting,the Company would continue to collect
import and export data on an hourlybasis.See Response to Production Request No.6.
Consequently,under an hourly netting interval,the Company would still use the same input data
as the real-time interval to calculate the hourly net exports for each customer.
The Company affirms that data will be available to customers at the hourly level.See
Response to Production Request No.9.However,Staff believes that under an hourlynetting
interval there will be an apparent inconsistency for those unfamiliar with the netting calculation.
This additional calculation and separation from the raw data reduces understandability by
complicating customer's bills.Additionally,because the Company will be using real-time
interval data to determine the net hourly interval imports and exports,the Company will incur
additional cost with no additional benefit over implementing a real-time measurement interval.
See Supplemental Response to Production Request No.8.
From the analysis presented above,Staff believes that a real-time measurement interval is
more accurate,more understandable,and more malleable than a net hourly interval.Staff
recommends that the Commission order the Company to implement a real-time measurement
interval for its ECR.
Time Period Rate-Differentiation based on System Reliability Risk
The Company's proposal for the ECR is a seasonal time-variant rate structure.This type
of rate design structure creates higher rates in the proposed "On-Peak"summer season of June
15 to September 15 between the highest risk hours of 3pm to 11pm.Support for these hours is
based in the 2021 Integrated Resource Plan ("IRP")analysis of the highest risk hours and
STAFF COMMENTS 12 OCTOBER 12,2023
seasons on the Company's system presented in its filing to modify the seasons of its Demand
Response ("DR")programs in Case No.IPC-E-21-32.
In contrast to the time periods proposed for the ECR,the Company maintains an optional
TOU consumption rate schedule that charges higher rates during higher risk hours.For
residential customers under Schedule 5 the TOU rates have a seasonal "On/Off-Peak"structure
corresponding to only the highest risk hours.For Schedule 9,19,and 20 customers,the TOU
hours include Mid-Peak pricing.In the Company's concurrent General Rate Case ("GRC")
filing,Case No.IPC-E-23-11,the Company is proposing to change the TOU peak hours for
Schedule 5 customers to occur between 7pm and 11pm.For TOU schedules with Mid-Peak
pricing,the Company is proposing to change the timing of Mid-Peak pricing to 3pm to 7pm and
11pm to 12am with On-Peak pricing from 7pm to l lpm.Additionally,the Company is
proposing to extend its summer season one month to span from June 1 to September 30.As
described in the testimony of Connie Aschenbrenner filed in the GRC,the proposals for TOU
hours and extending the summer season are based on preliminaryanalysis performed for the
Company's 2023 IRP that have shown an increasing trend of high-risk later in the summer
season and in the later hours of the day.The Company's GRC was filed on June 1,2023,and at
that time the Company requested an extension from the Commission to extend the file date of its
IRP to the last business day of September 2023.See Case No.IPC-E-23-17 and Order No,
35837.
The difference in the proposals for the ECR and TOU rates can be attributed to the timing
of the 2023 IRP highest risk analysis,which was not completed in time to be used for the ECR
filing.In both filings,support for the proposals was provided by the same type of "Highest
Risk"analysis.This analysis is based out of the Company's Reliability and Capacity
Assessment Tool ("RCAT").The RCAT is a computing tool that uses hourly load and
generation data inputs to calculate a Loss of Load Probability ("LOLP")or risk that the
combination of all the resources on the Company's system will be unable to meet load for each
hour of the year.The Company uses the hourly LOLP values to determine hours and seasons of
highest risk.Hours of highest risk are determined directly from the LOLPs for each month.The
analysis considers the hours of the top ranked LOLPs that correspond to 50%of all the risk
within the month.
STAFF COMMENTS 13 OCTOBER 12,2023
In Response to Production Request No.96 in IPC-E-23-11,the Company's highest risk
analysis shows that the highest risk hours are between 3pm and 12am with the most risk
concentrated in a consecutive block between 7pm to l 1pm.The Company's proposals define the
7pm to l 1pm consecutive block as "On-Peak",the remaining high-risk hours as "Mid-Peak"and
all other hours as "Off-Peak".Additionally,the Company used the same analysis to define the
summer season (June 1 through September 30).Staff notes that the Company did not include its
Battery Energy Storage Systems ("BESS")in its analysis of the hours of highest risk.Staff is
concerned that by excluding BESS resources from the model,the analysis does not accurately
reflect the actual risk seen by the system.However,this resource type is a recent addition to the
Company's system and Staff will review this analysis as part of the Company's 2023 IRP and
future filings by the Company.Figure 1 below demonstrates that for the month of July,50%of
all risk is contained between the hours 4pm and 12am
Figure 1:example ofthe LOLP distribution used to determine the highest risk hours for the
month ofJuly
Distribution for July Highest-Risk Hours
30 illiliis liillillillii
34-¯¯
30-
25-
o21
O
o17-
e12-
4-
Hour of the Day
STAFF COMMENTS 14 OCTOBER 12,2023
When defining seasons of highest risk,the analysis aggregates the hourlyLOLP to a
monthlyperspective.This is done using a Loss of Load Expectation ("LOLE")or the
expectation that that Company will suffer a loss of load in a given month.LOLE is calculated by
taking the sum of the highest LOLP for each day in a month.Figure 2 shows the LOLE for each
month of a load and resource year of 2025 using a 2022 historical year.Consistent with the
proposed high-risk season,the vast majorityof the loss of load expectation is captured between
the months of June and September.
Figure 2 -Example of the LOLE for each month of2022.
LOLE by Month for 2022
0.07
0.06
0.05
m 0.04
o-0.03
0.02
0.01
0.00
1 3 5 7 9 11
Month
The Company uses its identified seasons and hours of highest risk to inform its CEYW
construction projects,DR programs,Demand Side Management ("DSM")avoided costs,TOU
consumption rates,and the proposed ECR.Of these programs,the CEYW,DR programs,and
DSM avoided costs are noted to have significant differences that separate them from the other
offerings,despite being informed by the same analysis.For the CEYW construction projects,
after the analysis is complete,the highest risk timing is locked in and does not receive updates.
DSM avoided costs are used to estimate the value of programmatic offerings.Finally,and most
notably,DR programs have additional analysis conducted that maximizes the effectiveness of the
programs given the limitations of their dispatch parameters.Despite similar analysis,Staff
believes that it is inappropriate use the same DR season (June 15 to September 15)for the ECR
STAFF COMMENTS 15 OCTOBER 12,2023
and that the method for determining these seasons is not directly comparable.Accounting for
these end uses leaves the TOU consumption rates and the proposed ECR for direct comparison.
Both rates are based on the same type of analysis presented in the Company's IRP filings and
both share an intended purpose of using price signals to encourage behavior that benefits the
Company's system.Because of the similarities between these offerings,Staff believes that it is
inappropriate to have a misalignment between the timing of the export credit and TOU rates
price signals.
Staff recommends that the Company align the summer seasons of the ECR to match the
summer season of June l to September 30 presented in the concurrent GRC.Staff notes that this
recommendation is to align the ECR seasons with those presented in the GRC and is based on
the Company's preliminaryanalysis presented in Response to Production Request No.96 in Case
No.IPC-E-23-11.Staff recommends that the seasons of highest risk for all rates be updated as
part of future general rate case filings as informed by the most recently filed IRP.Additionally,
Staff believes that,as proposed by the Company,a misalignment of the summer season for all
Schedules in the GRC and the ECR summer season will cause customer confusion.Staff
received numerous questions,comments,and concerns regarding this in Staff's Workshop and
through public comments regarding the misalignment of TOU and export credit rates.Staff
notes that this proposal interacts with the Company's proposal for On-Peak hours.If accepted by
the Commission,Staff s proposed summer season would have the effect of shiftingsome value
from the On-Peak rates to the Off-Peak rates and extending the On-Peak hours.Staff believes
this favors on-site generation customers by providing more value in accessible times.More
detailed analysis on these impacts is presented in the relevant sections below.
Based on analysis provided in Response to Production Request No.96 of Case No.IPC-
E-23-11,the combined Mid-Peak and On-Peak risk hours used to define the TOU rates span a
similar window as the proposed ECR,3pm to 12am and 3pm to l lpm,respectively.Due to this
similarity,Staff is comfortable with the Company's proposed On-Peak ECR hours of 3pm to
11pm for the summer season of June 1 to September 30.However,this does not negate the need
for continued alignment between the TOU and ECR highest risk hours.Staff recommends that,
as IRP analysis indicates a need to update hours of highest risk,the Company file a separate
docket to update the highest risk hours for both the ECR and TOU rates.
STAFF COMMENTS 16 OCTOBER 12,2023
Avoided Energy
Determination of Value
Staff agrees with the Company's proposed method for valuingavoided energy based on
ELAP pricing.The Company proposes that the value of avoided energy be determined by the
hourly prices from the Energy Imbalance Market ("EIM"),the western region's real-time energy
market.Since EIM prices vary from location to location,the Company proposes using the EIM
Load Aggregation Point ("ELAP")pricing,which is independently determined on an hourly
basis by the California IndependentSystem Operator ("CAISO").The Company proposes to use
the 12 months of market data ending December 31 of each year.Under the Company's proposal,
the avoided energy component of the ECR is calculated by multiplyingthe ELAP hourlyprice,
given in dollars per megawatt-hour ("MWh")of energy,by the total MWhs exported by
customer-generators each hour,yielding a total dollar value for all energy exported that hour.
The hourly values can then be summed up and distributed according to a method discussed in the
next section.
Staff believes that the use of hourly ELAP prices is reasonable because they reflect the
true market value of energy in the Company's service area in each hour.The price represents the
market value of non-firmenergy,which Staff believes is the correct classification of customer-
generator exports.Given the challenge of fairly adjusting the value of energy downward if it is
non-firm,Staff believes this aspect of ELAP pricing is a significant advantage.Lastly,ELAP
pricing is publicly available information through CAISO,which makes the use of ELAP values
transparent and verifiable.
Staff believes that using historic pricing data is reasonable.Historic pricing is less
accurate than real-time pricing as it creates a delay or lag between the current energy price and
when those prices are reflected in the value of the ECR,but it provides rate stability and
transparency for the customers.Staff believes it is more important to provide customers a fixed
set of published energy values for a year,than to assign an unknown and highly variable real-
time price to each unit of exportedenergy.If the proposed ECR were to use a shorter historical
data set or a real-time market price,the resulting rates would fluctuate often and offer no stability
for customers to plan their investments.Additionally,to keep the value of energy as accurate as
possible,Staff agrees with the Company's proposal to use the most recent year's pricing data,
and not to incorporate multipleyears of pricing data via some type of rollingaverage.
STAFF COMMENTS 17 OCTOBER 12,2023
Distribution of Value
Staff disagrees with the Company's proposed method to distribute the value of avoided
energy and recommends that the value of avoided energy be allocated between the Summer and
Non-Summer seasons and the definition of Summer and Non-Summer for the ECR be aligned
with the Summer and Non-Summer seasons for the corresponding consumptive tariffs proposed
in the Company's GRC.The Company proposes to distribute the energy value between an On-
Peak time window and all other hours,called the Off-Peak window.The Company claims that
the On-Peak hours are "currently identified as the hours of the Company's greatest system need
for energy and capacity."Ellsworth at 9.
Staff believes that the On-Peak time window is determined primarily by capacity
considerations,not energy considerations,as described in further detail in the System Reliability
Risk section above.Staff believes that it is inappropriate to distribute the energy value using a
time window defined by capacity.As the capacity-based hours span into the evening when solar
production is unavailable,the energy value assigned to those times would be unattainable by
most customer generators.
A better proposal is to assign the energy value in accordance with energy-defined
seasons.Staff proposes to distribute the energy value between the Summer and non-Summer
seasons that are established in the tariffed consumption rates.The Summer season has higher
volumetric consumption rates primarily because energy costs are higher in that season.It is
conceptually consistent,and therefore more accurate,to allocate the ECR avoided energy costs
in the same manner.This proposal also partlyresolves public comments that noted the
inconsistent times and seasons between consumption rates and ECR rates.Staff believes its
proposal is fairer to exporting customers because it allocates all the avoided energy value only to
seasons,and not to specific hours of each day (especially hours after dark),so the full energy
value is obtainable by all exporting customers.
A downside of having differing time periods between Energy and Capacity components
is that the combined ECR could have as many as four different values.The Company's proposal
would only have two ECR values,an On-Peak value and an Off-Peak value,because it defines
the times and seasons to be the same for Energy and Capacity.If the Summer season is extended
to September 30,as supported by Staff in the Company's general rate case,Staff's proposal
would produce three ECR values:Non-Summer,Summer Off-Peak,and Summer On-Peak.This
STAFF COMMENTS 18 OCTOBER 12,2023
incremental complexity is not unusual in the Company's optional Schedules.Staff believes this
small additional complexityis worth the benefits.
Comparison of Value
If the Commission accepts Staff's proposal and the definition of the Summer season of
June 1 to September 30,Staff calculated what the ECR energy rates would be and compared
them to the Company's proposed On-and Off-Peak energy rates in Table 2 below:
Table 2 -ECR Energy Value Comparison*
CompanyProposal Cents/kWh Staff Proposal Cents/kWh
On-Peak Summer
Jun 15 -Sep 15,3pm-1lpm,8.59 Jun 1 -Sep 30,all hours 5.66
excluding Sundays &
Holidays
Off-Peak Non-Summer4.91 4.84AllotherdaysandhoursOct1-May 31,all hours
*Based on the Company's 2022 data and inclusive of the Company's proposed line losses and
integration costs.
Althoughthe Summer energy rate is less than the On-Peak rate,Staff believes that the
longer season and more inclusive hours will return the energy value more fairly to customers
within each class.The Company's proposal would favor customers whose systems could export
late in the day,such as systems with battery storage and west-oriented systems.
Avoided GenerationCapacity
Determination of I/alue
Staff believes that the Company's proposed method for valuing avoided generation
capacity of exports is reasonable.However,to increase the stability,accuracy,and transparency
of the proposals,Staff recommends that the Company implement the following:
1.Using a 5-year rollingwindow instead of a 3-year rollingwindow to estimate
Effective Load Carrying Capability ("ELCC")values;
2.Modifying the method used to incorporate line losses in calculating capacity
value;and
3.Using all exports from customer generators in its calculation of the ELCC.
STAFF COMMENTS 19 OCTOBER 12,2023
The Company proposes to determine the capacity contribution of all customer generation
(measured in total kilowatts)and multiplyit by the levelized capacity cost of the least expensive
dispatchable resource (measured in $per kilowatt per year).
Staff agrees with the Company's proposal to use the levelized capacity cost of the least
expensive dispatchable resource as determined in the most recently filed IRP.The Company has
used this convention to value capacity costs in other cases and it is consistent to continue this
practice.In the 2021 IRP,the least-cost resource is the Simple Cycle Combustion Turbine
("SCCT"),valued at $131.60 per kilowatt per year.However,on September 30,2023,the
Company filed the 2023 IRP.In this edition,the least expensive dispatchable resource is still the
SCCT,with a levelized cost of $145.94 per kilowatt per year.Staff recommends that this
updated value be used to determine the avoided capacity value because it is more current and
therefore more accurate.
To determine the capacity contribution of customer-generators,the Company proposes
multiplyinga rolling 3-year average of the ELCC percentage by the hour of maximum exports,
thereby yieldingthe equivalent megawatts of perfect generation.Staff believes the ELCC is a
reasonable method to determine a resource's capacity contribution.Electric utilities are
beginning to adopt methods similar to the Company's ELCC method because it measures a
resource's contribution during the hours of highest risk,which are often different from the hours
of highest system load.The true value of avoided capacity occurs during the hours of highest
risk,so the ELCC is a more accurate means of assigning value.Older capacity methods such as
the National Renewable Energy Laboratory ("NREL")8,760-hour method,or the Peak Capacity
Allocation Factor ("PCAF")method assess a resource's contribution during the hours of highest
system load,not necessarily during the hours of highest risk,and are therefore less accurate.
Althoughthe Company proposes a 3-year rollingaverage of ELCC values,Staff
recommends increasing the ELCC to a 5-year rollingaverage.This is because Staff is concerned
the ELCC will trend down as solar penetration increases.Utility-scalesolar generators can lock
in their ELCC percentage through a contract with the Company,but this is not practical for a
class of customers with customers who enter and exit the class on an ongoing basis.Staff
believes a reasonable workaround is to extend the duration of the rolling average so the ELCC
values of early years can continue contributing to the overall capacity value for a longer period.
The year 2020 was the first year ELCCs could be accurately determined for customer exports,so
STAFF COMMENTS 20 OCTOBER 12,2023
a full 5-year average would not be attainable until the end of 2024.Therefore,if the
Commission accepts Staff's recommendation,the rollingaverage would incorporate each year's
result as it became available through 2024.
Staff proposes a modification to how the Company incorporates line losses into the
calculation of capacity value.The Company marks up the customer exports and feeds the
marked-up values into its MATLAB scripts that calculate the ELCC.In theory,the grossed-up
exports yield a slightly higher ELCC result than if the unmodified values were used.However,
Staff believes that the ELCC algorithms do not have the resolution to account for the small line
loss increases,thus line losses are effectivelynullified.Because the Company performs these
calculations using complicated MATLAB scripts,verification by Staff is extremely difficult.
Staff therefore proposes that the Company account for line losses for capacity in the same
manner as it does for energy,by applying the line loss gross up after the ELCC and avoided
capacity values are determined.This approach is simpler and more transparent to all parties and
will likelyproduce more accurate results.
Staff disagrees with one of the Company's ELCC calculation steps.In its response to
Production Request No.2,the Company disclosed that it zeroes out all customer exports except
the ones that occur during the On-Peak hours,and inputs that modified export profile into the
ELCC algorithm.Even though most of the contributions to capacity occur during the On-Peak
hours,Staff believes that some contributions to capacity may occur outside those hours.
Therefore,the Company should include all exports in its calculation of the ELCC.The
Company should be calculating the full value of avoided capacity value throughout the entire
year,not just the avoided capacity value during the On-Peak hours.The subsequent distribution
of that value is discussed in the section below.
Distribution of Value
Staff believes the Company's proposal to distribute all the generationcapacity value to
the On-Peak hours is reasonable.The Company proposed to distribute the value of avoided
generation capacity to its On-Peak hours.The On-Peak hours correspond to the hours of highest
risk discussed at length in the preceding section on Rate Design Structure.
Staff agrees with the Company's assertion that "The procurement of capacity resources is
driven by the identified hours of highest risk...."Ellsworth Direct at 17.This means that
STAFF COMMENTS 21 OCTOBER 12,2023
customer exports that occur during the hours of highest risk are principallyresponsible for
avoiding the need and cost for additional capacity.Therefore,the value of avoided generation
capacity should be distributed during those periods when capacity costs are avoided,which occur
during the hours of highest risk.This has the added advantage of sending a price signal to
incentivize customers to export energy during these hours.Details of Staff's analysis of the
definition of On-Peak hours can be found in the Time Period Rate-Differentiation Based on
System ReliabilityRisk section above.
Comparison of Values
Table 3 below compares the On-Peak capacity values using the 2021 avoided resource
value and the 2023 avoided resource value.
Table 3 -ECR Capacity Value Comparison*
Units 2021 IRP 2023 IRP
Levelized Fixed Cost of Avoided Resource $/kW-year $131.60 $145.94
On-Peak Avoided Generation Capacity Value cents/kWh 11.59 12.85
*All calculations use the Company's original line loss value and method for applying the line
losses.Proposed changes to the line loss rate and ELCC calculations are not captured.
Avoided Transmission and Distribution Capacity ("T&D")
Determination of Value
The Company compares T&D capacity shortfalls throughout its system and overlays
customer exports to determine how long it can delay projects that increase T&D capacity.The
value is determined based on the cost of capital of the project investment and the length of time a
project can be delayed.Staff believes the Company's proposed method of project-by-project
deferral assessments is reasonable and agrees that assessing every T&D capacity project over a
20-year time span is sufficiently comprehensive.
Staff recognizes the validityof the Company's long-establishedprocess to identify future
T&D capacity shortfalls by forecasting local load growth and comparing it to T&D capacity
limits.However,Staff has concern about the auditabilityof the final step,the overlay of
customer exports and the identification of capacity deferrals.Because the total value of T&D
STAFF COMMENTS 22 OCTOBER 12,2023
project deferrals is less than 1%of the overall ECR value,Staff concludes that the risk is low and
the proposed approach is reasonable.
Distribution of Tralue
The distribution of value for avoided T&D capacity follows the same reasoning as the
distribution of value for avoided generation capacity,as discussed in the preceding section.In
short,the avoided capacity value should be distributed only to exports during the hours of
highest risk because those are the hours when the value is truly earned.Staff believes the
Company's proposal to distribute all the T&D deferred capacity value to the On-Peak hours is
reasonable.
Avoided Line Losses
In its Application the Company opted to update the line loss analysis using 2022 data
included as Exhibit No.4,rather than line loss data from a 2012 study utilized in the VODER
Study.The Company's data shows overall losses declined from 9.7%in 2012 to 7.6%in 2022.
Both values are higher than the nationwide average of 5%.6
Staff reviewed the report and the underlyingcalculations and concluded that the analysis
is reasonably accurate but disagrees with the Company's proposed coefficients.
Determination of Value
The electric utility industry typically calculates line losses in two ways.'The first way
calculates the system losses over the entire year,and the second way calculates the system losses
during the peak hour of the year.The Company performed both calculations as part of its study
but attempted to calculate the losses during the On-Peak and Off-Peak periods.To do this,the
Company used hourlydata from its 138-kV system to serve as a proxy to modify the peak and
energy calculations.Staff believes this approach embeds too many assumptions,obfuscates the
calculations,and jeopardizes accuracy.Also,it is inappropriate to apply a capacity-based loss
rate to the ECR energy value.
6 U.S.Energy InformationAdministration estimate of annual T&D losses in the United States 2017-2021.
7 DistributionSystem Losses Evaluation by Electric Power Research Institute,December 2008;Chapter 3.
STAFF COMMENTS 23 OCTOBER 12,2023
Staff recommends that the ECR utilize the industry-typicalloss calculations,not the
Company's unique extrapolation of those losses.The avoided energy value should be grossed up
by the standard annual energy loss coefficient and the avoided capacity value should be grossed
up by the standard peak hour loss coefficient.This more accurately aligns the loss measurements
with each of the avoided values.It also streamlines any future studies by only using the
industry-typicalcalculations.Overall,Staff believes this approach is more accurate and more
transparent.
Comparison of Tralue
Table 4 below compares the proposed loss coefficient values:
Table 4 -ECR Line Loss Coefficient Comparison
Company Proposal Staff Proposal
On-Peak =1.050 Capacity =1.053
Off-Peak =1.044 Energy =1.044
Avoided Environmental Costs
The Company has not proposed to include any avoided environmental benefits.For its
analysis,Staff considered a national carbon tax,an Idaho Renewable Portfolio Standard ("RPS")
policy,social health,and RECs as options that could be used to provide a value of an
environmental benefit.
There are currentlyno mandated Carbon Tax,RPS policy,or other environmental costs
to the Company on a state or federal level.Outside of a mandate there is no other identified
environmental benefit that has a direct and quantifiable impact on the Company's rates.
Commission Order No.35631 at 28.Regarding Renewable Energy Credits ("RECs"),
ownership remains with the owner of the on-site generation system absent an RPS or other
legislation.Until a state or federal legislation mandates a quantifiable environmental cost or
adder to the Company's rates,it is not appropriateto include any associated environmental
benefits in the ECR.
STAFF COMMENTS 24 OCTOBER 12,2023
Integration Costs
The Company proposes to use its 2020 VER integration study to provide an integration
cost of $0.00293/kWh to be accounted as a reduction to the proposed ECR.An integration study
is a study that is periodicallyconducted by the Company to quantifythe cost of regulating
variable,non-firm energy sources into the Company's system such as those used by customer-
generators.Due to the scope of the Company's integrations studies,Staff does not expect that
changes to the NEM will not directly affect the forecasts or validityof the 2020 study's
estimation of integration costs.In its Response to Production Request No.35,the Company
stated that the previous integration study considered VER penetration levels beyond what is
currentlyon the Company's system.Staff agrees with the Company's basis for and inclusion of
the $0.00293/kWh integration cost in the ECR.
While the proposed integration costs have been thoroughlyreviewed through the IRP and
are well supported for inclusion in the ECR,Staff believes that the Company should be using
integration costs authorized by the Commission for ratemaking purposes.In the past,after a new
study is completed,the Company has filed an update to Schedule 87 (intermittentGeneration
Integration Charges)and once authorized,it is used to determine avoided cost rates for PURPA.
The last time Schedule 87 was updated was in July of 2016,even though subsequent VER
studies have been conducted.Staff recommends that the Commission:(1)authorize the
integration rates for purposes of the ECR rates in this filing;(2)direct the Company to file the
2020 VER study for Commission authorization to update Schedule 87 and to be used in future
ratemaking that requires it includingfuture updates to CEYW and ECR-related rates;and (3)
direct the Company to file all future VER studies and integration costs for Commission
authorization,if integration cost have materiallychanged from those authorized.
Billing Impacts of Proposed ECR Rates:
Most on-site generation customers will experience the largest impact of the change to the
ECR in their bills.Under the Company's proposal,non-legacy customer generators will no
longer be able to bank energy credits (NEM)to offset their consumption usage and customers
will now receive a financial credit (ECR)for their exports which can then be used to pay any part
of their bill.The Company estimates the average non-legacy customer bill to increase
approximately $12 for Schedule 6,$15 for Schedule 8,and $12 for Schedule 84.This rate can
STAFF COMMENTS 25 OCTOBER 12,2023
vary significantlyfor each customer usage and export patterns,but in general customers that tend
to consume higher amounts of energy will experience the greatest financial impact.
STAFF COMMENTS 26 OCTOBER 12,2023
Table 5 -Schedule 6 Average Bill Impact"
Averate Bill Im a act
Avg.Monthly Bill
Category Count NEM Net Billing
0 kWh 642 $5.00 $l1.56
1 5 500 kWh 2,123 $22.50 $34.88
500 5 900 kWh 563 $62.38 $76.23
900 5 1,300 kWh 197 $99.31 $115.60
1,300 5 1,700 kWh 110 $137.46 $155.75
1,700 kWh+119 $235.01 $251.90
All Customers 3,754 $39.63 $51.75
Table 6 -Schedule 8 Average Bill Impact
Averaie Bill Im.act
Avg.Monthly Bill
Category Count NEM Net Billing
0 kWh 6 $5.00 $10.09
1 5 200 kWh 4 $15.02 $38.36
200 5 400 kWh 1 $30.32 $61.25
400 5 600 kWh -$-$-
600 5 800 kWh -$-$-
800 kWh+2 $108.75 $126.72
All Customers 13 $25.99 $40.67
Table 7 -Schedule 84 Average Bill Impact *
AveraieBillImsact
Avg.Monthly Bill
Category Count NEM Net Billing
0 kWh 2 $16.00 $16.00
1 5 500 kWh 2 $43.86 $61.29
500 5 900 kWh 2 $60.03 $76.52
900 5 1,300 kWh 1 $117.57 $131.40
1,300 5 1,700 kWh 1 $135.77 $152.49
1,700 kWh+-$-$-
See Response to StaffProduction Request No.1,Attachment 1 -Response to StaffRequest No.1 -Residential
See Response to StaffProduction Request No.1,Attachment 2 -Response to StaffRequest No.1 -Small General
10 See Response to Staff Production Request No.1,Attachment 3 -Response to StaffRequest No.1 -Large
General
STAFF COMMENTS 27 OCTOBER 12,2023
All Customers 8 $61.64 $73.94
Bill Impacts under StaffProposal
Under Staff's proposal,while the summer On-Peak rate is slightly reduced from the
Company's On-Peak rate,customers will have a greater period of time to earn a higher value for
exports to the Company's system.For On-Peak summers hours,customers would have a total of
824 hours to receive the higher ECR versus the Company's proposed season for On-Peak hours
of 634 hours.In the summer Off-Peak hours,customers will receive a higher value for exports
than they would have under the Company's proposal,$0.0569 per kWh versus $0.0491.As
displayed in Table 8 below,on-site generators will have a greater amount of exports fall under an
increased ECR.
Table 8 -Company vs StaffProposed On-site Generators Exports"by Season
Schedule 6 Schedule 8 Schedule 84
Company Staff Company St__ff Company Kff
On-Peak Summer On-Peak On-Peak Summer On-Peak On-Peak Summer On-Peak
Exports Exports Exports Exports Exports Exports
3,983,767 5,564,344 37,646 49,883 2,233,620 3,138,484
Off-Peak Summer Off-Peak Off-Peak Summer Off-Peak Off-Peak Summer Off-Peak
Exports Exports Exports Exports Exports Exports
54,566,619 19,472,826 382,060 138,049 30,872,551 7,719,923
Non-Summer Non-Summer Non-Summer
Exports Exports Exports
33,513,216 231,774 22,247,763
Total Exports Total Exports Total Exports
(kWh)58,550,387 (kWh)419,706 (kWh)33,106,171
Staff estimates that under its proposed ECR,residential customer generators could see an
average net bill of approximately $46,an increase of approximately $9.However,this value can
change significantlybased on an individual customer generator's export and consumption
profiles.Staff believes that under its proposed ECR,customer generators will ultimatelyhave
more opportunityto maximize their exports during the summer season;thus,increasing their
"Total Exports are based on Legacy and Non-legacy customer generators.
STAFF COMMENTS 28 OCTOBER 12,2023
ability to control the financial impact of changing from the current NEM rate structure to an ECR
and providing exports to the system during the Company's highest risk months and hours.
Combined billingImpacts ofProposed ECR and General Rate Case:
Concurrent to this filing the Company filed a GRC.The Company requested an overall
rate increase of 8.61%with an effective date of January 1,2024.If the Company's proposed
changes in the GRC are accepted,on-site generation customers could face additional bill impacts
from the overall rate increase and from changes in the Company's monthlyservice charges.
Notably,the Company has proposed to increase the residential service charge from $5 to $35
over a 3-year transition period.If approved,this could increase customer fixed charges by $30,
this will likelyresult in a significant increase to a customer generator's net bill in any given
month.Additionally,the Company has proposed to offer TOU to Schedule 6.Staff notes that
the offering of TOU rates for Schedule 6 customers provides customers with further opportunity
to maximize exports and the financial impact of the ECR and GRC,if they are approved.
Updates to ECR
Table 10 below details the Company's proposal to update the various inputs that inform
the ECR.The Company proposes to file updates annuallyon April 1,to be effective June 1.
This timeline is consistent with the Company's other annual update filings also referred to as
spring filings.
STAFF COMMENTS 29 OCTOBER 12,2023
Table 9 -Company proposal for ECR component updates.
Real-Time Exports Avoided Energy;Annual
12 months ending Dec 31 Avoided Generation Capacity
ELAP Hourly Market Prices Avoided Encrgy Annual
12 months ending Dec 31
Contribution Capacity -ELCC Avoided Generation Capacity Annual
3-year rolling average
Peak Annual Exports Avoided Generation Capacity Annual
Total MW
Levelized Cost of Avoided Resource Avoided Generation Capacity Routine -Most recently
Cost per &W-year filed IRP
Hours of Capacity Need Avoided Energy;Routine -Most recently
On-Peak Hours Avoided GenerationCapacity filed IRP
Transmission &Distribution Deferral Avoided Transmission &Routine -Most recently
Annual Deferral Value Distribution Capacity filed IRP
Line Loss Study Avoided Line Losses Routine -Updated with
Loss Coefficients periodic line loss study
Variable Energy Resource Integration Integration Costs Routine -Updated with
Study periodic VER Study
Under the Company's proposal,the real-time exports,ELAP hourlymarket prices,
contribution capacity -ELCC,and peak annual exports component inputs are updated annually
based on historical export and market data.As described in the section on the determination of
the avoided energy value,using historical data provides some stability to the ECR.Under the
Company's proposal,Staff believes updating these inputs on an annual basis is a reasonable
amount of time between updates to help ensure that rates closely resemble market conditions
while balancing the need for rate stability for customer generators.Additionally,while there is
an inaccuracy in current market conditions created by the lag,by regularlyupdating the ECR,the
value of past rate years is captured across the life of the system with each subsequent update to
the ECR.Staff agrees with the Company's proposal to file updates to the real-time exports,
ELAP hourly market prices,and peak annual exports annuallyon April 1.Additionally,Staff
agrees with updating the contribution capacity -ELCC with the addition of Staff's
recommendationto move to a 5-year rolling average.In its Response to Production Request No.
40,the Company states that the timing of the annual filing is driven in large part by ELAP
market data,which is not fully reconciled until 70 business days after the last day of the
historical year.Data from the Company's system is available as early as March.Staff
STAFF COMMENTS 30 OCTOBER 12,2023
recommends that the Company be prepared to respond to audit requests on this information
before the filing date.
For the remaining inputs,the Company has proposed to update them on a routine basis.
These inputs are based on various other Company filings that are completed on a consistent
cycle.Each of the inputs listed in Table 9 except for the Hours of Capacity Need are related to
updating the input data used to calculate the ECR.The Hours of Capacity Need is the only input
that would update the structure of the ECR and change the methodology for how the ECR is
calculated.In comparison,all of the Company's spring filing updates are limited to updating the
input data behind the calculation for the filing's respective adjustment.None of these filings
update the methodology or change the way these calculations are performed.Because Staff's
analysis in these filings is limited to verifying the updates to data inputs and not fundamental
changes to the methodology,it is possible for these cases to operate on the accelerated timeline
of being filed in April and going into effect on June 1.If the Company were to update the hours
of capacity needed as part of a condensed filing timeline,Staff would not be able to complete a
thorough review of the proposed changes and their supporting documentation.Staff agrees with
the Company's proposal to update the levelized cost of avoided resource,transmission &
distribution deferral,line loss,and variable energy resource integration cost inputs on a routine
basis specific to each input as proposed in the table above.However,Staff disagrees with the
Company's proposal to update the Hours of Capacity Need input for On-Peak hours in the
proposed April filing.Staff recommends that the Commission order the Company to update the
Hours of Capacity Need component of the ECR in a separate filing.This filing should be
submitted by the Company on an as needed basis as informed by analysis provided in the
Company's IRP planning process.Any changes to the structure of the ECR (i.e.,season length,
hours,how credits are applied,etc.)should trigger a new case with ample time for all parties to
review and provide input.
Finally,The Company proposes to file its first update April 1,2024.Staff believes that
under the Company's proposal,Customers will not have had sufficient time to adjust to the new
rate.From the proposed ECR effective date of January 1,2024,on-site generationcustomers
would only receive three bills showing the impact of the ECR before the Company files its first
update.Staff believes this may cause customer confusion and recommends that the Company
delay the first update to the ECR until June 1,2025.Staff believes that the Company can use
STAFF COMMENTS 31 OCTOBER 12,2023
this "acclimation period"to provide educational materials and for customers to adjust to the
updated ECR billing structure.
Modifications to Project Eligibility Cap
Staff's evaluation of the project eligibilitycap is based on three criteria:(1)eligibility
caps should be set to help minimize cost impacts to other non-participating customers;(2)
eligibilitycaps should be set to ensure the safety and reliability of the Company's system;and
(3)eligibilitycaps should be set to align with the program's intent,which is to allow customers
to offset their own consumption.In its evaluation,Staff agrees with the Company's eligibility
cap proposals for Schedule 84 customers,Schedule 6 and 8 customers,and customer generators
under all three schedules with energy storage.However,Staff has identified additional
recommendations beyond the Company's proposals.
Project Eligibility Cap for Schedule 6 and Schedule 8 Customers
The Company does not propose any change to the eligibilitycap for Schedule 6 and
Schedule 8 customers because the Company believes that the current cap of 25 kW is not
limitingfor these customers.Anderson Direct at 5.For example,the average residential
customer service point maximum annual hourlydemand is approximately 6 to 7 kW,and the
most commonly installed residential system is about 7.5 kW,or 30%of the 25 kW cap.
Anderson Direct at 5.
The Company believes that Schedule 6 and Schedule 8 customers are dissimilar to
Schedule 84 customers in two ways.First,a higher percentage of customer service points
registered an annual demand in excess of the existing cap for Schedule 84 customers.Nearly 8%
of non-solar commercial and industrial customers and 13%of non-solar irrigation customers
registered an annual peak demand of over 100 kW.See Responses to Staff Production Request
Nos.16 and 20.However,only 2%of Schedule 6 and Schedule 8 service points registered an
annual peak demand in excess of the existing cap.See Response to Staff Production Request No.
17.Second,there are Schedule 84 customers with larger demands who desire to install larger
on-site generation systems.Those customers have installed smaller,disaggregated 100 kW
systems and transferred kWh credits annuallyto qualifying service points under the existing
"meter aggregationrules".Application at 21-22.
STAFF COMMENTS 32 OCTOBER 12,2023
Staff agrees with the Company's reasoning,and Staff recommends maintaining the
current Schedule 6 and Schedule 8 eligibilitycaps but monitor when the cap becomes limiting
and consider changes to the cap if warranted.
Project Eligibility Cap for Schedule 84 Customers
In its Application,the Company proposes modifying the Schedule 84 Project eligibility
cap to 100kW or 100%of demand.The Company's Revised Study Framework in Case No.IPC-
E-21-21 includes analysis of 100%and 125%of a customer's demand for determining the
project eligibilitycap.However,the Company proposes 100%of the customer's demand,
instead of 125%of the demand.The Company.provides the followingrationale:
First,the Company believes that a cap larger than 100%of the demand cannot be
implemented without system upgrades,which will require all customers to pay for the ongoing
cost associated with the upgrades,even though the initial cost is paid for by the on-site
generation customer.Second,the Company does not routinelyinstall facilities larger than
customer demand in any other situation.Third,100%of the demand can ensure the Company
does not have oversized distribution equipment on its system.Fourth,100%of the demand
aligns well with the intent of allowing a customer to offset their energy usage behind the meter.
See Response to Staff Production Request No.15.Lastly,customers who desire to install an on-
site generation system larger than 100%of demand can do so by becoming a QualifyingFacility
under Schedule 86 (non-firm energy)or Schedule 73 (firm energy),or choosing the non-
exporting option.See Response to Staff Production Request No.45.
Staff agrees with the Company's reasoning,and Staff recommends approval of the
Company's proposed eligibilitycap for Schedule 84 customers,which is the greater of 100 kW
or 100%of demand.
How Demand is Determined for Schedule 84 Customers
The Company proposes different methods for determining a Schedule 84 customer's
demand for purposes of conforming to the 100%eligibilitycap,depending on the following
circumstances:
A:For customers with at least 12 months of historical billingdata,the maximum
billing demand from the last 12 months is used.
STAFF COMMENTS 33 OCTOBER 12,2023
B:For new customers or those without at least 12 months of historical billingof their
own,the Company will evaluate and rely on available historical billing data at that
service point.If customers believe their demand will exceed that of the past
customer,the Company proposes requiring an analysis of the facility's power needs
performed by a professional engineer and paid by the customer.
C:For new customers or those who neither have at least 12 months of historical
billingof their own nor have historical billingdata at the service point,the Company
proposes requiring an analysis of the facility's power needs performed by a
professional engineer.
D:For irrigation customers without a full in-season billinghistory,a conversion
factor related to the horsepower of their pumps at the service point will be used to
determine the maximum demand.
Application at 22 and Anderson Direct at 9.
Staff mostly agrees with the Company's proposal;however,Staff is concerned with
Scenario B as described above,because the Company would only require an analysis be
performed by a professional engineer when a customer "believes"their demand will exceed that
of a past customer.
Staff assumes that the Company intends to have the on-site customer pay for the analysis,
which will prevent cost shifts to other customers.However,Staff believes that it may discourage
customers from wanting to incur the additional cost and bias their beliefs,resulting in an
inadequately sized interconnection that could affect reliability.Althoughthis may not affect the
Company's system,Staff believes the Company should play a more active role and verify the
need for the analysis rather than relying on the customer's beliefs.In all cases of additional
analysis,Staff believes the cost should always be charged to the on-site customer.
Staff recommends the Company play a more active role in determining whether a needs
analysis needs to be conducted,ensure the analysis is paid by the customer,and incorporate into
the Schedule 84 language the Company's proposed methods used to determine a customer's
demand relative to the Schedule 84 cap.
STAFF COMMENTS 34 OCTOBER 12,2023
Demand Changes After Installation for Schedule 84 Customers
The Company proposes to maintain a customer's current system size if a customer's
demand decreases or if a new customer takes over the premises with a lower power requirement.
If a customer's demand increases after the initial installation,an expansion can be conducted
pursuant to Schedule 68 by applying for a system modification.Application at 22-23 and
Anderson Direct at 9-10.
Staff agrees with this proposal but recommends that the description of the treatment be
incorporated in Schedule 84 language.Staff also recommends the description should clarify that
an expanded system is still subject to the project eligibilitycap,which is the greater of 100 kW
or 100%of demand at the service point.
Additional Interconnection Requirements for Schedule 84 Customers
The Company proposes the followingadditional interconnection requirements in
Schedule 68 to accommodate the increase of the project eligibilitycap for Schedule 84.
Inverter-basedgeneration of 100 kW and greater will provide documentationto validate
inverter settings.
A power plant controller or a properly configured inverter will be installed on the
customer's side of the point of delivery for systems 500 kW and greater.
The existing uniform interconnection agreement and requirements applicable to non-
exporting systems larger than 3 MW will apply to systems 3MW and greater.
Ellsworth Direct at 31.
Staff recommends approval of these changes in Schedule 68 necessary to interconnect
exporting systems larger than 100 kW safely and reliably due to the increase of the project
eligibilitycap for Schedule 84.
Project Eligibility Caps for Systems with Energy Storage
The Company proposes that for systems with energy storage devices,l2 only the amount
of generationnameplate capacity be used to determine whether the cap is exceeded for Schedules
12 Energy storage devices can share an inverterwith the generation facility ("DC coupled")or connect to a stand-
alone inverter ("AC coupled").Staffbelieves this proposal only applies to AC-coupled energy storage devices,not
DC-coupled energy storage devices because Idaho Power only collects the informationof nameplate capacity of the
STAFF COMMENTS 35 OCTOBER 12,2023
6,8 and 84.Anderson Direct at 13.If the sum of generation capacity and storage capacity is
exceeded,the Company allows upgrades to the system as long as the customer pays the upfront
cost."However,Staff is concerned with incremental "ongoing"costs of system upgrades
beyond the upfrontcosts that can shift to other customers.For these reasons,Staff has
considered three options to address the potential additional cost:
Option 1:Accept the Company's proposal and allow ongoing costs associated with
system upgrades to be spread to all customers,if the costs are minimal;
Option 2:Accept the Company's proposal but apply a surcharge for ongoing operation
and maintenance costs ("O&M")to customers who require system upgrades;
Option 3:Reject the Company's proposal and maintain the status quo where the capacity
of energy storage is included in the calculation of the total nameplate capacity
of the on-site customer's system subject to the respective eligibilitycaps.
Under the current Schedule 6,Schedule 8,and Schedule 84,when a customer seeks to
add energy storage devices,and if the combined capacity of the generating resource and the
energy storage devices exceeds the project eligibilitycap,the Company must deny the
customer's interconnection application.See Response to Staff Production Request No.25 (a).
For example,if a residential customer has a solar generation system of 22 kW paired with an
AC-coupled energy storage device of 4 kW,the total nameplate capacity is 26 kW,which
exceeds the project eligibilitycap of 25 kW for Schedule 6 customers.See Response to Staff
Production Request No.25 (c).If the solar generationsystem and the AC-coupled energy
storage device export energy simultaneously,the capacity being delivered to the Company's
system would be 26 kW.See Response to Staff Production Request No.26.Under the current
eligibilitycaps,the Company must deny the customer's interconnection application.
The Company proposes to exclude the capacity of energy storage in the calculation of the
nameplate capacity of the on-site generationfacilities for determining whether the nameplate
capacity exceeds the project eligibilitycap but will consider the capacity of energy storage in the
inverters,and only the capacity size of AC-coupled energy storage devices is known.Response to Staff Production
Request No.37."Staffobtained this informationthrough a conference call with the Company on September 5,2023.
STAFF COMMENTS 36 OCTOBER 12,2023
feasibilityreview process.See Response to Staff Production Request No.25 (b).The
Company's proposal will allow all on-site generation customers (Schedule 6,Schedule 8,and
Schedule 84)to install generation capacity up to their respective project eligibilitycaps,while
allowingthem to add additional energy storage capacity.See Response to Staff Production
Request No.25 (b).
The Company believes the feasibility review will verify whether the interconnection of
the combined system will be sufficient and will not jeopardize the safety or reliability of the
Company's system.See Response to Staff Production Request No.25 (b).After the review,if
the Company believes the customer's combined system will require a system upgrade,the
customer will be required to pay all of the upfront costs.However,the Company's proposal does
not require incremental on-going O&M costs be paid by the customer and these costs could be
shifted to non-generating customers.14
Throughits evaluation,Staff considered the magnitude of the ongoing costs.If these
costs are minimal,accepting the Company's proposal and allowingongoing costs associated
with system upgrades to be spread to all customers may be reasonable.However,if the costs are
not minimal,Option 2,accepting the Company's proposal but applying a surcharge to customers
who require system upgrades,would be preferred.Staff rejected Option 3,the status quo,
because it does not accommodate customers that currentlyhave large amounts of generation
capacity close to the current cap who desire to install a battery to offset their consumption.Staff
also believes Option 3 should be rejected because systems with storage can provide significant
benefits to the Company's system by reducing the Company's net peak loads,especially if the
cost impact to other non-exporting customers is minimal.
Staff's final recommendation is Option 2 because the Company could not provide the
amount of ongoing cost of system upgrades to determine if the costs were minimal.See
Response to Staff Production Request No.53.Staff expects this Option to protect other
customers from cost shifts,meet customers'needs,and increase the amount of storage capacity
beneficial to the Company's system.Furthermore,the Company believes a surcharge could be
14 An example of an ongoing O&M cost would be the replacement of a larger and more costly failed transformer
required by the system upgrade.Staffobtained this informationthrough a conference call with the Company on
September 5,2023.
STAFF COMMENTS 37 OCTOBER 12,2023
implemented similar to the Facilities Charge in Schedule 68 that requires customers with non-
exporting system of three megavolt-ampereor larger to pay for ongoing maintenance costs.Id.
Staff recommends approving the Company's proposal to exclude the capacity of energy
storage and only include the nameplate capacity of generationto enforce the eligibilitycap but if
a customer requires a system upgrade,the customer be required to pay all upfrontcosts and
ongoing costs through a surcharge.
Other ImplementationConsiderations
Recovery of ECR Expenditures
The Company recommends recovery of ECR expenditures as a net power supply expense
subject to 100%recovery through the PCA.The recommendation is similar to the VODER
Study presented in IPC-E-22-22,which Staff maintains is appropriate.
Staff agrees with the Company that the energy purchased from self-generators is a must-
take resource and should be recovered through the PCA.Application at 23.Like PURPA,Staff
believes the Company has no choice whether it can take Schedule 6,8,and 84 customer exports
as a matter of policy and should be recovered at 100%through the PCA without customer
sharing.Order No.35607 at 12.
Financial Credit Use and Transferability
In the Application,the Company is proposing two recommendations for future use and
transferability of accumulated financial credits.The Company has recommended that non-
legacy customers be allowed to pass financial credits to other accounts in the customer's name.
The second request is to allow the financial credits to be applied to all billingcomponents,
including customer service charge,energy-relatedportion,riders,and other components.
Implementing an ECR and allowingcustomers to use the financial credit to be applied to all
billing components may incentivize non-legacy customers and future customers to maximize
their solar systems during peak hours,which may be to the benefit of all customers.Staff does
not take issue with this request.As such,Staff recommends that non-legacy customers be
allowed to transfer financial credits to other accounts in their name.
STAFF COMMENTS 38 OCTOBER 12,2023
Financial Credit Expiration
In its proposed tariff language for Schedules 6,8,and 84,the Company added the
followingunder the conditions of purchase and sale for net billing.
Credits are non-transferrable in the event that a customer relocates and/or
discontinues service at the Point of Deliveryassociated with the Exporting
System.Any unused credits will expire at the time the final bill is prepared.
While the language is consistent with the net metering section in the tariffs,Staff believes
there should be a distinction between the non-transferabilityof kWh credits under legacy net
Metering,and the financial credits under the proposed Net Billing structure.Under the proposed
language,when a customer relocates to another location on the Company's system or
discontinues service with the Company,any fmancial credits that the customer has earned by
exporting energy to the Company's system will expire.For kWh credits,this methodology
appears reasonable as the Company is unable to transfer a unit of energy within its system or to
another utility's system.However,for financial credits under the proposed net billing,this will
result with customer on-site generators being uncompensated for energy that they provided to the
Company.Staff believes that the Company's reasoning provided in Response to Production
Request No.54 is insufficient to support denying an on-site generationcustomer's compensation
for exported energy that has a quantifiable benefit to the Company.
Staff recommends that the Commission order the Company to transfer financial credits to
the customers new meter when a customer relocates within the Company's system or refund the
amount of accumulated financial credits to the customer in the event they relocate outside the
Company's system and to adjust the tariff language in a compliance filing.
Accumulated kWh Conversion Rate and Timeframe
Company witness Grant Anderson's testimony outlines that any accumulated kWh credits
will be converted to a financial figure after one year,or after December 31,2024.Anderson
Direct at 21-22.The Company anticipates using a blended average retail energy rate as of
December 31,2023,to convert any excess kWh credits.
STAFF COMMENTS 39 OCTOBER 12,2023
The formula to calculate a blended average retail energy rate for each non-legacy
customer class is to sum charges for energy,the FCA,and the PCA,then divide by the total kWh
consumed.
Staff recommends approval of the Company's use of a blended average retail energy rate
to convert excess accumulated kWh credits at the end of 2024.Staff is unaware of how
customers may be notified of this conversion.Therefore,Staff recommends the Company notify
each non-legacy customer that has excess kWh credits as of December 31,2024,of how their
excess credits will be converted,at what rate,and how it will be displayed on their next bill.
Regarding the conversion to a financial credit,Staff supports the Company's proposal that the
conversion of accumulated kWh credits to a financial credit be recovered through the FCA for
Residential and Small General Service customers and the PCA for Commercial,Irrigators and
Industrial customers.
Transition Period
The Company,the Commission,and several intervening parties have been involved in
changing the NEM program since 2017 through a multitude of dockets summarized earlier in
these comments.Staff believes the processing of these dockets has provided customers with
enough notice of potential changes that additional transition to an ECR is not necessary.
For these reasons,Staff does not recommend any transition period.Staff believes that
allowingcurrent non-legacy customers to use accumulated kWh credits over the 2024 calendar
year will provide enough transition and opportunityfor current NEM customers to learn the new
program.
However,as indicated earlier in the ECR Update Section,Staff proposes the first update
to the ECR to begin in 2025 rather than 2024.Staff believes an acclimation period is necessary
for customers to adjust to the ECR billing structure without having the ECR billingrate change
in the first 6 months of a new program.
"Company Responses to Staff Production Request Nos.51 and 52.
STAFF COMMENTS 40 OCTOBER 12,2023
STAKEHOLDER AND CUSTOMER COMMUNICATION
Public Workshops
On August 15,2023,the Commission issued a press release announcing two virtual
public workshops.The first IPUC workshop was held the evening of September 6,2023,and the
second was held on the afternoon of September 7,2023.Among the topics discussed at the
workshop were the VODER study,historyof the case,and grandfathering.Where appropriate,
Staff attempted to address customers'comments and concerns in these areas.The workshops
were well attended with approximately 106 customers that participated in the September 6,2023
evening workshop and approximately 42 customers participated in the September 7,2023
afternoon workshop.
Customer Comments
As of October 11,2023,231 public comments have been filed in this case.Of the 234
customers who offered comments,108 customers (47%),identified as non-legacy customers,
while only 7 (3%)clearly identified themselves as legacy customers.There were another 68
customers (30%)who have net-generation system but did not identify their status,whether
legacy or non-legacy.
Previous Orders
Customers continued to express concerns regarding grandfathering with 94 customers
(41%)stating that all current net generations customers should be granted legacy status.Another
46 customers (20%)claimed they were not aware of possible changes to the program at the time
they had their systems installed.These customers stated they would not have gone forward had
they known the rates would change.
There were 58 customers (25%)who disagreed with the outcome of IPC-E-22-22,
including34 customers (15%)who challenged the objectivity of the VODER study,and 24
customers (10%)who suggested that the Commission failed to consider third party studies and
the concerns of interested parties.There were 83 customers (36%)who urged further
consideration of environmental benefits.
STAFF COMMENTS 41 OCTOBER 12,2023
Structure and Compensation
Regarding any change to compensation,153 customers (67%)wanted no change to the
structure of the program,and 136 customers (59%)wanted to keep monthlynet metering versus
real time metering.Regardingthe accrued kwh credits accumulated by both legacy and non-
legacy customers,41 customers (18%)expressed concern about the future value and traceability
of accumulated credits as well as advocated for customer options for the applicability of those
credits.
Regarding financial credits under the proposed changes,33 customers (14%)worried
about the accountability of those financial credits and the value of those credits.Of the 21
customers (2%)who offered comments on the ECR,13 customers (1%)wanted the ECR tied to
retail rates,and 8 customers (1%)expressed a desire for an unbiased annual review of ECR rates.
There were 45 customers (20%)who offered comments regarding compensation for peak
versus non-peakhours,time-of-day versus peak and non-peakhours,seasonal demand versus
customer peak hours and use of a single rate versus peak and non-peakhours.Peak hours
compensation extends into the evening even as generation declines and suggested that
compensation for peak hours should start earlier in the day.
Incentives
There were 79 customers (34%)who said the Company needs to provide more incentives
to customers to encourage net generation.
STAFF RECOMMENDATION
Staff Recommends the Commission:
1.Implement Staffs proposals for a real-time net billingwith an avoided cost based,
seasonal,time-variant,ECR,with the followingrecommendations:
a.Adjust the On-Peak season to align with the summer season proposed in the GRC.
Direct that updates to the season be part of future general rate case filings;
b.Accept the On-Peak hours,as proposed by the Company,but direct that if future
IRP analysis indicates a need to update the hours of highest risk,the Company
should file a separate docket;
STAFF COMMENTS 42 OCTOBER 12,2023
c.Distribute the avoided energy value in alignment with the summer and non-
summer seasons,as determined in the GRC;
d.Use the most current levelized capacity cost for the least-cost dispatchable
resource from the 2023 IRP;
e.Use a five-year rollingaverage of the ELCC percentage to determinethe avoided
capacity value;
f.Calculate the ELCC and avoided capacity values without the line loss gross up,
and subsequently apply the line loss gross up to that result;
g.Include all customer exports in the calculation of each year's ELCC;
h.Use the industry-typicalline loss calculations.Apply the annual energy line
losses to the energy value,and the peak hour line losses to the capacity value.
2.Direct the Company to update all proposed components of the ECR except the hours of
highest risk in an annual filing beginning April 1,2025.
3.Direct the Company to update the hours of highest risk in a separate filing on an as-
needed basis.
4.Maintain the current Schedule 6 and Schedule 8 eligibilitycaps but monitor when the cap
becomes limitingand consider changes to the cap if warranted.
5.Approve the proposed eligibilitycap for Schedule 84 customers:the greater of 100 kW
and 100%of demand and:
a.Incorporate into Schedule 84 the Company's proposed methods used to determine
a customer's demand relative to the Schedule 84 cap.
b.Direct the Company to play a more active role to verify the need for a
professional engineer to conduct an analysis to determine a new customer's
demand requirements.
c.Direct that the cost of such analysis should be charged to the on-site generation
customer.
d.Incorporate into Schedule 84 the description of the Company's proposed
treatment when a customer's demand changes;and
e.Clarify in Schedule 84 that an expanded system is still subject to the project
eligibilitycap,which is the greater of 100 kW or 100%of demand at the service
point.
STAFF COMMENTS 43 OCTOBER 12,2023
6.Incorporate the Company's additional proposed interconnection requirements in Schedule
68 due to the increase of the project eligibilitycap for Schedule 84.
7.Approve the Company's proposal to exclude energy storage and only include the
nameplate capacity of generation to enforce the eligibilitycap for Schedules 6,8,and 84;
and to require the customer to pay all upfront and ongoing costs of system upgrades
through a surcharge,if upgrades are needed.
8.Approve the Company's request to recover ECR expendituresas a net power supply
expense subject to 100%recovery through the PCA.
9.Approve the Company's proposals on the use and transferability of financial credits.
10.Approve the Company's proposal to convert accumulated kWh credits to financial credits
using a blended average retail energy rate on December 31,2024,and:
a.Direct the Company to notify each non-legacy customer that has excess kWh credits
as of December 31,2024 of how their excess credits will be converted,at what rate,
and how it will be displayed on their next bill.
11.Direct the Company to transfer or refund any accumulated fmancial credits in the event a
customer relocates or discontinues service.
12.Authorize the integration rates from the 2020 Variable Energy Resource ("VER")study
as proposed for purposes of the ECR rates in this filing,and:
c.Direct the Company file an update to Schedule 87 rates and integration costs from
the 2020 VER study for Commission approval to be used in future ratemaking
that requires it,includingupdates to Clean Energy Your Way ("CEYW")and
ECR-related rates.
d.Direct the Company to file all future VER studies and integration costs for
Commission authorization,if integration cost have materiallychanged from those
authorized.
13.Direct the Company to adjust the language of Tariff Schedules 6,8,and 84 according to
all recommendations presented above in a compliance filing.
STAFF COMMENTS 44 OCTOBER 12,2023
Respectfully submitted this 12th day of October 2023.
,Chris Burdi
'Deputy AttorneyGeneral
Technical Staff:Jason Talford
Matt Suess
Yao Yin
Mike Louis
Travis Culbertson
Chris Hecht
Jolene Bossard
Dylan Moriarty
i:umisc/comments/ipce23.14jjtmsmltncchjbdmcomments
STAFF COMMENTS 45 OCTOBER 12,2023
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 12th DAY OF OCTOBER 2023,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF TO
IDAHO POWER,IN CASE NO.IPC-E-23-14,BY MAILING A COPY THEREOF,
POSTAGE PREPAID,TO THE FOLLOWING:
LISA D NORDSTROM TIMOTHY TATUM
MEGAN GOICOECHEA ALLEN CONNIE ASCHENBRENNER
IDAHO POWER COMPANY GRANT ANDERSON
PO BOX 70 IDAHO POWER COMPANY
BOISE ID 83707-0070 PO BOX 70
E-MAIL:[e-mail] BOISE ID 83707-0070
[e-mail] E-MAIL:[e-mail]
[e-mail] [e-mail]
[e-mail]
ERIC L OLSEN LANCE KAUFMAN PhD
ECHO HAWK &OLSEN PLLC 2623 NW BLUEBELL PLACE
PO BOX 6119 CORVALLIS OR 97330
POCATELLO ID 83205 E-MAIL:lance aegisinsight.com
E-MAIL:elo echohawk.com
MATTHEW NYKIEL BRAD HEUSINKVELD
ID CONSERVATION LEAGUE ID CONSERVATION LEAGUE
710 N 6TH ST 710 N 6TH ST
BOISE ID 83702 BOISE ID 83702
E-MAIL:matthew.nykiel amail.com E-MAIL:[e-mail]
C TOM ARKOOSH MICHAEL HECKLER
ARKOOSH LAW OFFICES COURTNEY WHITE
PO BOX 2900 CLEAN ENERGY OPPORTUNITIES
BOISE ID 83701 3778 PLANTATION RIVER DR
E-MAIL:tom.arkoosh arkoosh.com STE 102
BOISE ID 83703erin.cecil arkoosh.com .E-MAIL:[e-mail]
[e-mail]
KELSEY JAE
LAW FOR CONSCIOUS LEADERSHIP
920 N CLOVER DR
BOISE ID 83703
E-MAIL:[e-mail]
CERTIFICATE OF SERVICE
AUSTIN RUESCHHOFF JIM SWIER
THORVALD A NELSON MICRON TECHNOLOGY INC
AUSTIN W JENSEN 800 SOUTH FEDERAL WAY
HOLLAND &HART LLP BOISE ID 83707
555 17TH ST STE 3200 E-MAIL:[e-mail]
DENVER CO 80202
E-MAIL:[e-mail]
[e-mail]
[e-mail]
[e-mail]
clmoser hollandhart.com
DARRELL EARLY WIL GEHL
DEPUTY CITY ATTORNEY ENERGY PROGRAM MANAGER
BOISE CITY ATTORNEY'S OFFICE BOISE CITY DEPT OF PUBLIC WORKS
PO BOX 500 PO BOX 500
BOISE ID 83701-0500 BOISE ID 82701-0500
E-MAIL:[e-mail] E-MAIL:[e-mail]
[e-mail]
ABIGAIL R GERMAINE KATE BOWMAN REG DIR
ELAM &BURKE PA VOTE SOLAR
PO BOX 1539 299 S MAIN ST STE 1300
BOISE ID 83701 PMB 93601
E-MAIL:[e-mail] SALT LAKE CITY UT 84111
E-MAIL:[e-mail]
SECRETARY
CERTIFICATE OF SERVICE