20230511Comments.pdf

CLAIRE SHARP
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE,IDAHO 83720-0074
[phone]
IDAHO BAR NO.8026
Street Address for Express Mail:
11331 W CHINDEN BLVD,BLDG 8,SUITE 201-A
BOISE,ID 83714
Attorneyfor the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )COMPANY'S APPLICATION FOR )CASE NO.IPC-E-23-12
AUTHORITY TO IMPLEMENT POWER )COST ADJUSTMENT ("PCA")RATES FOR )ELECTRIC SERVICE FROM JUNE 1,2023 )COMMENTS OF THE
THROUGH MAY 31,2024 )COMMISSION STAFF
COMMISSION STAFF ("STAFF")OF the Idaho Public Utilities Commission
("Commission"),by and throughits Attorneyof record,Claire Sharp,Deputy Attorney General,
submits the followingcomments.
BACKGROUND
On April 14,2023,Idaho Power Company ("Idaho Power"or "Company")applied for
Commission authorization to implement its PCA rates in Schedule 55-Power Cost Adjustment
("Schedule 55")effective June 1,2023,through May 31,2024.Application at 1.The Company
requests to increase overall revenue throughSchedule 55 by approximately $200.2 million or
14.68 percent.Id.at 1-2 If approved,the Company's PCA would increase rates for all customer
classes and residential rates would increase 11.90 percent.
The PCA mechanism permits the Company to increase or decrease its PCA rates to
reflect the Company's annual Net Power Supply Expense ("NPSE").Due to its diverse
STAFF COMMENTS 1 MAY l1,2023
generationportfolio,the Company's actual cost of providing electricity varies from year to year
dependingon changes in such things as the river streamflow,the amount of purchased power,
fuel costs,the market price of power,and other factors.The annual PCA surcharge or credit is
combined with the Company's "base rates"to produce a customer's overall energy rate.The
Company stated that neither it nor its shareholders receive any financial return from the PCA -
money collected from the surcharge may be used only to pay NPSE.Id.at 3.
The PCA quantifies and tracks annual differences between actual NPSE and the
normalized or "base level"of NPSE recovered in the Company's base rates,resulting in a credit
or surcharge that is updated annuallyon June 1.The PCA mechanism uses a 12-month test
period from April through March ("PCA Year")and includes a forecast component and a
Balancing Adjustment.The forecast component represents the difference between the
Company's NPSE forecast from the March Operating Plan and base level NPSE recovered in the
Company's base rates.The Balancing Adjustment includes a backward-looking tracking of
differences between the prior PCA Year's forecast and actual NPSE incurred by the Company,
and also tracks the collection of the prior year's Balancing Adjustment.
Except for Public Utility Regulatory Policies Act of 1978 ("PURPA")expenses and
demand response ("DR")incentive payments,the PCA allows the Company to pass through to
customers 95 percent of the annual differences in actual NPSE as compared with base level
NPSE,whether positive or negative.With respect to PURPA expenses and demand response
incentive payments,any actual annual expense deviations from base level NPSE,the Company is
allowed to pass 100 percent of the difference for recovery or credit through the PCA.The PCA
is also the rate mechanism used by the Company to provide customer benefits resulting from the
revenue sharing mechanism,approved in Order No.34071.
The Company system-level forecast for NPSE for the 2023-2024 PCA Year is $541.5
million,which is $235.8 million higher than the 2022-2023 PCA Year.The forecast is primarily
driven by higher forecast natural gas and market energy prices,combined with a limited coal
supply.Id.at 8-9.
The Balancing Adjustment at the end of March 2023,includinginterest,was
approximately $190.2 million and was primarily driven by high natural gas and market energy
prices,combined with a limited coal supply.Also,hydro generation in the 2022-2023 PCA Year
was nine percent lower than forecast.Id.at 9-10.
STAFF COMMENTS 2 MAY l1,2023
Under Order No.34071,the Commission requires the Company to share revenue with its
customers if its Idaho jurisdictionalyear-end return on equity ("ROE")is ten percent or greater.
The Company asserts its Idaho jurisdictionalyear-end ROE in 2022 was below the ten percent
ROE threshold for revenue sharing.Thus,the 2023-2024 PCA will not include a revenue
sharing component.Id.
The Company's uniform PCA rate for the 2023-2024 PCA Year is comprised of (1)the
1.4572 cents per kilowatt-hour ("kWh")adjustment for the 2023-2024 forecasted power cost of
serving firm loads under the current PCA methodology and 95 percent sharing,and (2)1.2714
cents per kWh for the 2022-2023 Balancing Adjustment.Together these two components result
in an approximate 2.7286 cents per kWh charge for all rate classes.Id.at 10.
STAFF ANALYSIS
The Company's proposed update to Schedule 55 reflects an increase in billed revenue of
approximately $200.2 million,or 14.68 percent,effective June 1,2023.Staff recommends
approval of the Company's Application with reservations,as presented below.This
recommendation is based on Staff's review of the Application,audit of sampled transactions,
examination of the testimony and workpapers of Company witness Jessica G.Brady,and a
review of the Company responses to Staff's audit and production requests.
Staff examined the Company's sales and expenses for the historical 2022-2023 PCA
year and its forecasting methods,projected revenues,and expenses for the upcoming 2023-2024
PCA year.Staff also verified that the Company's filing and methods complied with prior,
relevant,Commission Orders.Staff concludes that:
1.The Company's forecast for the upcoming PCA year (2023-2024)of electricity
sales,loads,fuel consumption,fuel costs,and purchased power costs are
reasonable;
2.The Company should notify the Commission if the forecast materially deviates
during the PCA Year and if an adjustment to the forecast rate is warranted,the
Company should make an off-cycle filing;
3.The Company's balancing adjustment for the last PCA year is reasonable but
Staff has concerns about the prudency of the NPSE;
STAFF COMMENTS 3 MAY 11,2023
4.The Commission should allow actual NPSE included in the filing to be used to
calculate the PCA deferral and Schedule 55 rates,but the Commission withhold
its decision on whether actual NPSE is prudent,until the Company,with Staff's
review,fully investigate the circumstances that led to the lack of coal supply and
provide a report on its findings to the Commission,which should include the
items outlined in the NPSE section;
5.The Commission should reserve the right to adjust the recovery of the NPSE
until next the next PCA filing if the Company was not prudent in its management
of coal supply;
6.The Company should notify the Commission of the outcome of the damage
claim for Hells Canyon Unit No.3;and
7.The Commission should accept late filed comments by customers.
Components of the Proposed PCA Increase
The components of the $200.2 million increase in the PCA are shown in Table No.1
below.
Table No.1:Revenue Impactby PCA Rate Component,Idaho Basis
2022-2023 2023-2024PCAIPCA2 DifferencePCAForecast$169,966,873 $218,005,217 $48,038,344
PCA Balancing Adjustment $38,583,273 $190,208,504 $151,625,231
PCA Total $208,550,146 $408,213,721 $199,663,575RevenueSharing$(568,435)0 $568,435
Total Revenue Impact $207,981,710 $408,213,721 $200,232,011
The Company's NPSE varies each year depending on factors,which may include
changes in river streamflow,the amount of purchased power,fuel costs,market energy price of
I Because Table 1 contains the expected billed revenue impact to customer,the "2022-2023 PCA"column reflectsapprovedPCAratesappliedtotheJune2022throughMay2023salesforecastandwillnottietothespecificdollaramountsapprovedinthe2022PCAfiling.
2 The "2023-2024 PCA"column reflects the Company's proposed rates applied to the June 2023 through May 2024forecastandmaynottieexactlytothefigureslistedintheCompany's application due to the rounding of rates to sixdigits.
STAFF COMMENTS 4 MAY l1,2023
power,and a limited coal supply.The PCA trues up annuallyto differences between actual
NPSE and the NPSE collected through base rates.With the PCA,customers are paying the
actual NPSE incurred by the Company.
The Company's power supply costs and surplus sales are subject to a 95 percent/5
percent sharing band,with the Company responsible for 5 percent of the excess NPSE compared
to NPSE revenue the Company collected throughbase rates.The Commission created this
sharing band to provide a financial incentive for the Company to make careful resource
acquisition and operating decisions to reduce costs.If actual costs are less than revenue
collected,the Company keeps 5 percent of that difference.If costs are more than revenue
collected,customers pay 95 percent of the excess costs,and the Company absorbs 5 percent.
1.Forecast Analysis
Based on the 2023-2024 PCA forecast,the Company expects to collect $218.0 million
from Idaho customers.Staff believes the 2023-2024 PCA forecast is reasonable and any over-or
under-collected amounts due to forecast variance will be trued-up in the followingyear.
The Company used its March 2023 Operating Plan to forecast the difference between
NPSE embedded in base rates and NPSE the Company expects to recover in the coming year.
The Company uses a dispatch simulation model to analyze projected load and to determine and
analyze resource balance and energy supply for the upcoming PCA Year.The forecast also
accounts for forward market energy prices,hydro generation,fuel prices,existing hedge
transactions,and costs associated with PURPA and non-PURPA contracts.
In its forecast,the Company projects forward market energy prices,available hydro
generation,coal and natural gas prices,and any existing hedge transactions.The Company
analyses the forecast against the resulting monthlyheavy load and light load dispatch to
determine a monthlyload and resource balance.Staff recommends the Company keep Staff
appraised of how the forecast changes during the PCA Year and if an adjustment to the forecast
rate is warranted,the Company should make an off cycle filing with the Commission.
2.BalancingAdjustmentAnalysis
The Balancing Account incorporates additional components into the PCA as shown in
Table No.2 below.
STAFF COMMENTS 5 MAY l1,2023
Table No.2:Balancing Account Summary
Amount
Beginning Balance $38,669,526
2022-2023 Incremental Deferral $343,410,716
2022-2023 Forecast Revenues Collections $(164,503,384)
2022-2023 Prior Balance Revenues Collected $(28,095,102)
Revenue Sharing $(571,382)
Current Month Interest $1,295,196
2022-2023 EndingDeferral Balance $190,205,569
Staff discussion will focus on the Incremental Deferral balance for the period of April
2022 through March 2023 first,followed by the remaining components.
Incremental Deferral Balance
The incremental deferral balance of $343 million includes two expenses:(1)the expense
difference between actual NPSE from April 1,2022,to March 31,2023,and NPSE recovered
through base rates;and (2)other PCA expenses.Table No.3,below,summarizes the two
components of the Incremental Deferral balance and are the amounts allocated to Idaho
customers after the jurisdictional allocation and the 95 percent/5 percent sharing band are
applied.
Staff's review included:(i)a review and audit of the deferral components;(ii)an analysis
of the methods and the basis used to calculate the cost deferrals and account balances;(iii)an
examination of the actual NPSE,including the Company's energy risk management policies and
actions;and (iv)an analysis to determine if the Company prudentlydispatched resources,
purchased power,and sold power in the wholesale market.Based on its review,Staff has
confidence that the Company's proposed deferral is accurate and that it conforms to past
Commission Orders.However,Staff has concerns about the prudency of the NPSE,as discussed
in the NPSE section below.
STAFF COMMENTS 6 MAY l1,2023
Table No.3:PCA Incremental Deferral Balance Summary
Amount
NPSE $328,080,234
Other PCA Expenses $15,330,481
Total Incremental Deferral Balance $343,410,716
NPSE
The $328 million in actual NPSE is the main contributor to the $190 million ending
deferral balance that is proposed for recovery.The Company determined and Staff verified that
the root cause for the extraordinarily high amount was a lack of coal supply needed to run the
Company's coal plants,especially during early winter months that experienced colder than usual
temperatures.Based on the previous PCA forecast,there are indications that the Company had
sufficient lead time to prevent or mitigate these costs.Because of the abnormally large PCA
balance this year,Staff recommends that the Commission authorize the use of actual NPSE in the
Company's deferral to calculate the PCA rate for this case.However,Staff also recommends the
Commission withhold a determination of prudence for the Company's actual NPSE until such
time that the Company provide the Commission and ratepayers a full accounting of the coal
supply situation and resulting NPSE with the potential for adjustments in the balancing account
in next year's PCA.Staff recommends directing the Company to perform a full investigation
and to submit a comprehensive report within 6 months of the Commission's fmal order.
In addition,Staff and the Company performed a similar investigation of an extended
downtime for Hells Canyon Dam Unit No.3 ("Unit 3")that mostly occurred during last year's
PCA deferral period.Staff reviewed all supporting documentation and concluded that the
Company acted prudently to resolve the downtime as further discussed below.
Lack of Coal Supply
To gain insight as to how the $328 million NPSE was incurred,Table No.4 below
compares the Company's forecast at the outset of the 2022-2023 PCA year with the actual results
at the end of the PCA year.The quantities are the absolute values for the year,before the base
was removed,or any jurisdictional allocation,or the 95 percent sharing.At the end of the table,
STAFF COMMENTS 7 MAY 11,2023
the base is removed,and the jurisdictional allocation and 95 percent sharing are applied to reach
the $328 million NPSE.
Table No.4:Comparison of Forecast and Actual NPSE
ChangeForecastActual(Actual-Forecast)
Hydro 5,972,743 5,458,343 (514,400)
$-$-$
5,083,043 3,265,218 (1,817,825)
Coal $29.74 $29.08 $(0.66)
$151,179,160 $94,955,998 $(56,223,162)
2,556,322 2,716,835 160,513
Gas $30.93 $65.63 $34.70
$79,067,982 $178,317,313 $99,249,331
Market 1,580,326 4,297,723 2,717,397
Purchases $62.32 $94.22 $31.90
$98,482,808 $404,938,271 $306,455,463
3rd PafÍy TranSmission $5,149,239 $12,819,177 $7,669,938
Market (1,258,195)(1,455,119)(196,924)
Sales $51.73 $116.98 $65.25
$(65,085,848)$(170,224,982)$(105,139,134)
Total 13,934,239 14,283,000 348,761
Total Actual NPSE $268,793,341 $520,805,777 $252,012,436
Idaho Allocation $497,897,414
Idaho Base $(152,549,798)
Idaho NPSE $345,347,616
95%NPSE $328,080,235
Table No.4 shows that the Company under-producedthe planned quantity of less
expensive hydro and coal electricity and had to make up the difference through its gas plants and
by purchasing more from the market.The prices for gas and market electricity were
exceptionally high throughout the PCA period causing the Company to incur $357 million in
additional expenses.The additional expenses were partially mitigated because the high market
prices enabled the Company to recover an additional $105 million selling surplus energy.
Overall,the Company incurred $252 million in expenses beyond its forecasted amounts in last
year's PCA.
STAFF COMMENTS 8 MAY 11,2023
In summary,the three primary contributors to the cost overrun were 1)the sustained
higher-than-predicted prices for gas and market electricity;2)the underproduction of hydro
electricity;and 3)the underproduction of coal electricity.
The high prices for gas and market electricityare outside of the Company's control,and
can only be mitigated by hedging practices,which the Company utilizes.
The quantity of hydro energy that can be produced is primarily determined by the annual
hydro conditions,which are out of the Company's control.Hydrologicdata confirms that the
lower snowpack was the primary contributor to the reduced hydro generation for the year.Staff
investigated the possibility that hydro generationplants were unduly offline but found no
evidence of this.
The final primary contributor to the cost overrun was the underproduction of coal energy.
The Company had forecast the production of 5.1 million megawatt-hours ("MWh")of coal
energy,but only produced 3.3 million MWh,a deficit of 1.8 million MWh.To compensate for
this deficit,the Company had to purchase additional gas and market electricty at prices that were
two to three times more expensivethan coal electricty,which amounted to an additional $114
million.
Preliminary investigation of the cause determined that the Company was unable to obtain
sufficient coal to meet its generationtarget.Althoughthe Company provided evidence that it
was aware of this coal shortage in April of 2022,there is also evidence that the Company
leadership was not aware of the problem until September.The Company's main efforts to
remedy the coal shortage occurred late in the calendar year and were mostly unsuccessful.Staff
believes that the Company may have been able to take more effective action early in the calendar
year to increase its quantity of coal or to hedge for additional gas and market energy,thereby
avoiding some of the $114 million in additional cost.
Therefore,Staff recommends that the Company fully investigate the circumstances that
led to this situation and provide a report of its findings to the Commission.This report should be
inclusive but not limited to items listed below.
1.Provide an analysis that traces and compares the Company's coal generation
forecasts and the corresponding coal supply orders and deliveries starting in
January 2022 to the present documenting who was aware of any shortfall between
the two,and when;
STAFF COMMENTS 9 MAY l1,2023
2.Provide an analysis and a timeline of events such as decisions and actions taken
by the Company relative to coal supply contracts or investments to maintain coal
supply leading up to and includingshortages of coal supply that occurred during
the PCA year.
3.Discuss alternatives the Company considered and decision and actions taken by
the Company to mitigate the coal supply shortfalls,who initiated the actions,
when they were initiated,and the outcomes;
4.Discuss the feasibility of additional coal production or procurement in the first
half of the PCA year if the scope of the shortfall had been fully appreciated;
5.Discuss the feasibility of additional hedging measures in the first half of the PCA
year if the scope of the energy shortfall had been fully appreciated;and
6.Identify the specific dollar impact if the Company had sufficient coal to run its
plants when it was economic for them to run.
7.Discuss and fully explain what the Company will be doing differentlyin the
future to maintain operation of its coal plants needed to meet deliveryof
electricity at least cost to customers.
8.Provide an appendix to the report with documents that support the Company's
analysis and provides evidence showing what the Company knew,and when they
knew it.
Lastly,Staff recommends that the Commission reserve the right to adjust the recovery of
the NPSE if the evidence shows that the Company was not prudent in this matter in next year's
PCA.
Hells Canyon Unit No.3 Downtime
In last year's PCA,Case No.IPC-E-22-11,Staff identified that Unit 3 was offline from
June 2020 until May 2022.The Commission ordered the Company to "work with Staff to
review the timing of recent planned and unplannedmaintenance at Hells Canyon Unit 3...If the
review determines that the downtime could have been reduced and customers would have
experienced a net reduction in NPSE as a result,an adjustment should be included in the next
PCA to ensure customers were not harmed by the Company's planning."Order No.35421 at 9.
STAFF COMMENTS 10 MAY l1,2023
Staff met with the Company and were provided with detailed information regarding the
repairs,the unforeseen problems that developedduring the repairs,and the Company's diligence
in implementing solutions to the unforeseen problems.Unit No.3 was brought online in May
2022 so the impact to the 2022-2023 PCA year is minimal.Staff believes the Company acted
prudently,and considers the issue resolved.The Company also stated that it is pursuing
liquidated damages from the repair contractor and any recovery would be credited to the
customers,reducing a future NPSE.Staff recommends that the Company notify the Commission
with the outcome when the claim is resolved.
Other PCA Expenses
Other PCA expenses include the difference between forecast expenses from the prior
PCA Year and what is embedded in base rates:(1)Idaho Jurisdictional QualifyingFacility
("QF")and PURPA Expense Deferral;(2)the Idaho Revenue Adjustment from the Sales Based
Adjustment ("SBA")Rate;(3)the difference between actual DR incentive payments and
amounts recovered in base rates;(4)the Actual Renewable Energy Credit ("REC")revenues;and
(5)Idaho Power Energy Imbalance Market ("EIM")Participation Costs.
1.OF/PURPA Expense Deferral.PURPA contracts are not subject to the 95 percent
sharing band but are subject to jurisdictional allocation between the Company's Idaho and
Oregon customers.For the PCA deferral year,the actual Idaho jurisdictional PURPA expense
was $67.3 million above the amount embedded in base rates.This increases the deferral balance
to be recovered from customers.
2 SBA Rate.The difference in actual and base rate sales is multipliedby the SBA rate
of $26.72/MWh,as set in Order No.33307,to determine the over-or under-recovery of actual
NPSE due to sales that are higher or lower than sales used to determine base rates (subject to 95
percent customer sharing).This year,the Company calculates a $41.8 million SBA decrease to
the deferral balance due to the Company's over-recovery of actual NPSE.Staff audited and
analyzed the Company's SBA calculations by:(1)auditing actual sales;(2)confirming the SBA
rate and sales used to set base rates;and (3)verifying the Company's method for calculating the
SBA followingthe Commission's prior orders.Staff believes the Company accurately
calculated the SBA adjustment and complied with Commission orders.This decreases the
deferral balance to be recovered from customers.
STAFF COMMENTS 11 MAY l 1,2023
3.DR Incentive Pavments.The Company's DR incentive payments are not subject to
the sharing band and are whollyallocated to Idaho.Prudency of DR incentive payments will be
determined in the Company's annual Demand-Side Managementprudence filing currentlybefore
the Commission (Case No.IPC-E-23-10).Any DR disallowance in that case will be reflected in
next year's PCA deferral balance.Staff audited the Company's actual DR incentive payments
included in the 2022-2023 PCA deferral balance.Staff confirms that actual DR incentive
expenses in the deferral were $2.9 million less than the amount in base rates.That difference
lowers the deferral balance to be recovered from customers.
4.REC Revenues.In Order No.30818,the Commission required the Company to sell
all RECs it receives for renewable generationto benefit its customers.Staff audited the
Company's REC transactions in the PCA deferral year and verified that the amount included in
the deferral period is accurate.In the deferral year,the Company's revenues from REC sales
were $9.7 million.Currently,REC sales are not included in base rates.These incremental
revenues decrease the deferral balance.
5.EIMParticipationCosts.The Company's operation and maintenance expenses
attributed to its participation in the EIM are included in the PCA deferral in compliance with
Order No.34100.The benefits of the EIM market,such as lower energy purchase prices and
increased sales volume,flow throughthe PCA.Includingparticipation costs appropriately
matches costs with benefits.EIM costs and benefits will be reviewed in the next general rate
case when the Commission will determine which costs and benefits will be included in base
rates.Staff reviewed EIM participation costs and believe they are appropriately recorded and
accurate.Idaho's share of the EIM expenses is $2.5 million,which is added to the deferral
balance.
Forecasted Revenues Collected
The Company generated $164.5 million in revenues from its PCA forecast rates during
the current PCA year.Because the forecast rate changes each June,the deferral period reflects
the rates set in previous PCA periods.This amount lowers the overall deferral balance for the
2023-2024 deferral period.Staff verified the revenue that was collected during the PCA period.
STAFF COMMENTS 12 MAY l1,2023
Collections of the 2022-2023 Deferral Balance
Last year's PCA rates collected $28.1 million as authorized in Order No.35421.Staff
verified that the collection of the deferral balance revenues during the PCA period is correct.
Interest
The deferral balance accrues interest at the Commission-approved customer deposit rate
of one percent in 2022 and two percent in 2023.Staff verified the interest calculations to be
accurate.The interest accrued during the current deferral year is $1.3 million,which increases
the deferral balance.
Revenue Sharing and Rate Calculation
The revenue sharing mechanism,established in 2010 and last modified in Order No.
34071 in 2018,requires the Company to share revenues with customers based on its actual Idaho
jurisdictionalyear-end ROE,if it exceeds ten percent.In 2022,that ROE was below the ten
percent ROE,resulting in no revenue sharing benefit to customers.Staff reviewed the revenue
sharing inputs and calculations and agree that there is no revenue sharing.Staff believes that the
calculation follows the Commission-approved methodology from previous PCA filings.
PCA Rate Calculations
Staff reviewed the components that make up this year's PCA rates.Based on its review,
Staff believes that the methods used comply with Commission orders and are calculated
accurately.
Staff's review of all the rate components included verification that rates were calculated
accurately and that the Company's methods comply with Commission Orders.Staff confirmed
that the revenue requirement was allocated across customer classes on an equal cents per kWh
basis,which ensures that customers share the PCA revenue requirement based on the amount of
energy consumed.
To evaluate whether there is an opportunity for the Commission to alleviate the impact of
this year's PCA,Staff looked into whether a longer deferral is beneficial,or by adding tiered
rates.In Order No.29026,a multiple-yeardeferral of large PCA amounts was determined not in
the public interest given the uncertainty that was present in coal,water,and wholesale market
STAFF COMMENTS 13 MAY 11,2023
conditions.The Commission generally stated that the public interest is best served by recovering
the balance of the PCA over a single year rather than collecting the balance over multiple years
with concern with impacts in followingyears and that the PCA was designed for a single-year
recovery of actual PCA costs.In Order No.28722,the Commission granted an interim PCA
tiered rate structure for residential customers.However,in the next PCA filing,the Commission
eliminated the tiered rate structure,as the tiered rate structure may have had negative impact on
high energy users and may have caused unintentional cost shifting.Thus,Staff does not
recommend any adjustments or modifications to the development of rates designed to mitigate
the impact of the large PCA balance.
Overall Impact of Filings Effective June 1,2023
On March 15,2023,the Company filed its annual Fixed Cost Adjustment ("FCA")in
Case No.IPC-E-23-09.The Company's 2023 FCA filing proposes a $10.0 million decrease in
current billed revenue,or a 1.56 percent decrease,for Idaho Residential and Small General
Service customers,effective June 1,2023,through May 31,2024.
If the PCA and FCA applications are approved as filed,the combined impact is an overall
increase in current billed revenue of $190.2 million,or 13.94 percent.The Company has
proposed to implement the PCA and FCA rates on June 1,2023.The impact by revenue class is
reflected in the followingtables.
STAFF COMMENTS 14 MAY 11,2023
Proposed 2023-2024 Revenue Impactby Class:
Percentage Increase from Current Billed Rates by Proposed Change
PCA
Small Large
General General
Residential Service Service Large Power Irrigation
11.90%9.70%16.19%20.26%15.01%
FCA
Small Large
General General
Residential Service Service Large Power Irrigation
(1.56)%(1.63)%N/A N/A N/A
Total Combined Impact
Small Large
General General
Residential Service Service Large Power Irrigation
10.34%8.08%16.19%20.26%15.01%
Customer Notice and Press Release
The Company's press release and customer notice were included with its Application.
Staff reviewed the documents and determined that both met the requirements of Rule 125 of the
Commission's Rules of Procedure (IDAPA 31.01.01.125).The notice was or will be included
with bills mailed to customers beginning April 26 and ending May 25,2023.Customers whose
bills will be mailed on May 20,23,24,and 25,were sent a direct mail postcard.
Unfortunately,even with the Company's attempt to provide earlier notice to customers,
Staff is concerned that they will not have a reasonable opportunity to file timely comments with
the Commission by the May 11 comment deadline.Customers must have the opportunity to file
comments and have those comments considered by the Commission.Staff recommends that the
Commission accept late filed comments by customers.As of May 8,2023,the Commission
received twelve customer comments opposing the proposed increase.The majority of those in
opposition cited the high cost of living,inflation,and being on a fixed income.Some customers
expressed concern over the need for a rate increase when natural gas and coal prices are steadily
decreasing,and water flow levels are projected to be higher.
STAFF COMMENTS 15 MAY l1,2023
STAFF RECOMMENDATIONS
1.Staff verified the Company's forecast for the upcoming PCA year (2023-2024)of
electricity sales,loads,fuel consumption,fuel costs,and purchased power costs are
reasonable;
2.Staff recommends the Company notify the Commission if the forecast materially deviates
from what is approvedin this case during the PCA Year and if an adjustment to the
forecast rate is warranted,the Company should make an off-cycle filing;
3.Staff verified the Company's balancing adjustment for the last PCA year is reasonable
but Staff has concerns about the prudency of the NPSE;
4.Staff recommends allowing actual NPSE included in the filing to be used to calculate the
PCA deferral and Schedule 55 rates,but the Commission withhold its decision on
whether actual NPSE is prudent,until the Company,with Staff s review,fully investigate
the circumstances that led to the lack of coal supply and provide a report of its findings to
the Commission,which should include the items outlined in the NPSE section;
5.Staff recommends the Commission reserve the right to adjust the recovery of the NPSE
until next PCA filing if the Company was not prudent in its management of coal supply;
6.Staff recommends the Company notify the Commission of the outcome of the damage
claim for Hells Canyon Unit No.3;and
7.Staff recommends the Commission accept late filed comments by customers.
Respectfully submitted this day of May 2023.
Claire Sharp
Deputy AttorneyGeneral
Technical Staff:James Chandler
Travis Culbertson
Jason Talford
Matt Suess
Curtis Thaden
i:umisc/comments/ipce23.12csjetnejjtmsetcomments
STAFF COMMENTS 16 MAY 11,2023
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 1lth DAY OF MAY 2023,SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF,INCASENO.IPC-E-23-12,BY E-MAILING A COPY THEREOF TO THE FOLLOWING:
MEGAN ALLEN GOICOECHEA MATTHEW T LARKINLISADNORDSTROMTIMOTHYETATUMIDAHOPOWERCOMPANYJESSIBRADY
PO BOX 70 IDAHO POWER COMPANYBOISEID83707-0070 PO BOX 70E-MAIL:BOISE ID 83707-0070
[e-mail] E-MAIL:[e-mail]
[e-mail] [e-mail]
[e-mail] [e-mail]
SECRE ARY
CERTIFICATE OF SERVICE