20220516Comments.pdf

DAYN HARDIE
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 9917
' ' :- .lF I\
r..-.-'i-lYEu
, :,1 tji'i i ,: iti{ L: 26
Street Address for Express Mail:
1 133I W CHINDEN BLVD, BLDG 8, SUITE 2OI-A
BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
, .-t/-,qt
.. a-rV.l
IN THE MATTER OF IDAHO POWER
COMPAI\Y'S APPLICATION FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT (PCA) RATES FOR
ELECTRTC SERVICE FROM JUNE 1,2022
THROUGH MAY 31,2023
CASE NO. IPC-E.LZ.II
COMMENTS OF THE
COMMISSION STAFF
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STAFF OF the Idaho Public Utilities Commission ("Staff'), by and through its Attorney
of record, Dayn Hardie, Deputy Attorney General, submits the following comments.
BACKGROUND
On April 15, 2022, Idaho Power Company ("Company") applied for Commission
authorization to implement its Power Cost Adjustment ("PCA") rates effective June 1,2022,
through May 31,2023. The Company requested to increase revenue through Schedule 55 by
approximately $103.4 million or 8.27 percent. If approved, the Company's PCA would increase
rates for all customer classes and residential rates would increase 6.55 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 generation
portfolio, the Company's actual cost of providing electricity varies from year to year depending
on 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
ISTAFF COMMENTS MAY 16,2022
the Company's "base rates" to produce a customer's overall energy rate. The Company stated that
neither it nor its shareholders rcccive any financial return from the PCA, as money collected from
the surcharge may be used only to pay NPSE.
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 annually on, June l. The PCA mechanism uses a l2-month test period of April
through March ("PCA Year") and includes a forecast component and a Balancing Adjustment
(formerly referred to as the "true-up" and the o'true-up of the true-up"). 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 (o'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 DR 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 by the Commission in Order No. 34071.
The Company system-level forecast for NPSE is approximately $56.5 million higher in the
2022-2023 PCA year than2021-2022 PCA year. The forecast is primarily driven by the expected
reduction in hydro generation and increases in natural gas prices and market energy prices. The
Company also forecasts an increase in coal generation to serve its load and an increase in surplus
sales. .Id.
The Balancing Adjustment at the end of March2022, including interest, was approximately
$38.7 million and was primarily driven by a decrease in actual hydro generation and higher than
forecast market purchases, but offset partially by surplus sales.l
I The PCA Balancing Account for the 2022-2023 PCA year is approximately $38.7 million, which is approximately
$57.0 million higher the 2021 -2022 PCA y ear.
2STAFF COMMENTS MAY 16,2022
Under Order No. 34071, the Commission requires the Company to share revenue with its
customers if its Idaho jurisdictional year-end return on equity ("ROE") is 10.0 percent or greater.
The Company asserts its Idaho jurisdictional year-end ROE in 2027 was 10.02 percent, requiring
the Company to include $568,771 as the revenue sharing component of the 2022-2023 PCA.
The Company's uniform PCA rate for the 2022-2023 PCA Year is comprised of (1) the
1.1926 cents per kilowatt-hour ("kWh") adjustment for the 2022-2023 forecasted power cost of
serving firm loads under the current PCA methodology with 5 percent sharing, and (2) 0.2579
cents per kWh for the 2021-2022 Balancing Adjustment. Id. at 6-7. Together these two
components result in an approximate 1.4505 cents per kWh charge for all rate classes. Id. at7.
STAFF ANALYSN
The Company's original proposed update to Schedule 55 reflected an approximate $103.4
million increase in revenue, effective June 1,2022, through May 31,2023. The Company's
Response to Staff Production Request No. 8 detailed changes to the original forecast piece of the
PCA to reflect changes with Bridger availability as modeled in the PCA Forecast. The response
states,
...ldaho Power's filed PCA in this case reflected Bridger Unit 1 availability for
dispatch at the revised state implementation plan ("SIP") levels, and Bridger Unit
2 availability at a 25 percent level from June through October 2022 in light of
ongoing uncertainty related to Environmental Protection Agency negotiations.
Since the filing of the PCA, confidential settlement discussions have progressed to
a point where Idaho Power feels more confident in its ability to operate the Bridger
plant at levels higher than those included in the initial filing. As a result, Idaho
Power has calculated what the change in estimated net power supply expense
("NPSE") would be if Bridger is fully available for the summer of 2022. ... This
equates to an estimated $8.5 million decrease in total Idaho jurisdictional PCA
collection.
Staff recommends approval of the Company's Application using the updated Bridger
Assumptions for the PCA calculation and recommends the Company file updated Schedule 55
reflecting the updated Bridger assumptions. Staff recommends approval of a $94.9 million
increase in PCA revenue. This recommendation is based on Staff s review of the Application,
audit of sampled transactions, examination of the testimorry and workpapers of Company
witness Jessica G. Brady, and a review of the Company responses to Staff s audit and
production requests.
JSTAFF COMMENTS MAY 16,2022
A. Audit Review
Staff examined the Company's sales and expenses for the historical 2021-2022 PCA year
and its forecasting methods, projected revenues, and expenses for the upcoming2022-2023 PCA
year. Staff also verified that the Company's filing and methods complied with prior, relevant,
Commission Orders. Staff concludes that:
1. For the upcoming PCA year (2022-2023), the Company's forecast with the updated
Bridger assumptions, of electricity sales, loads, fuel consumption, fuel costs, and
purchased power costs are accurate and reasonable;
2. The Company reasonably and prudently incurred actual Net Power Supply Expense
to serve customers during the current PCA year (2021-2022); and
3. The Company's Idaho jurisdictional 2021 year-end ROE of 10.02% is accurate,
resulting in $568,771 revenue sharing returned to customers.
Components of Proposed PCA Increase
The components of the $94.9 million increase in the PCA are shown in Table No. 1 below.
Table No. 1: Revenue Impact bv PCA Rate Component.Idaho Basis
Rate Component 2021-2022
PCA2
2022-2023
PCA3
Difference
PCA Forecast as filed
PCA Forecast change due
to update in Bridger
assumptions
$ l3 1,825,063 $t78,795,145
($8,470,506)
$46,970,081
($8,470,506)
PCA Forecast with
updated Bridger
assumptions
$170,324,638 $38,499,575
PCA True-up/Balancing
Adiustment
($ I 8,320,281)$38,664,487 $56,984,768
Revenue Sharing $0 ($568,771)($568,771)
PCA Total $113,504,783 $208,420,355 $94,915,572
2 Because Table I contains the expected billed revenue impact to customer, the "202l-2022 PCA" column reflects
approved 2021-2022 PCA rates applied to the June 2022 throtgh May 2023 sales forecast and will not tie to the
specific dollar amounts approved in the 2021 PCA filing.
3 The "2022-2023 PCA" column reflects the Company's proposed rates applied to the June 2022 throtghMay 2023
forecast and may not tie exactly to the figures listed in the Company's application due to the rounding of rates to six
digits.
4STAFF COMMENTS MAY t6,2022
The Company's NPSE vary each year depending on several factors, including changes in
river streamflow, the amount of purchased power, fuel costs, and the market price of power. The
PCA mechanism trues up annually to differences between actual NPSE and the NPSE collected
through base rates. With the PCA, the Company's customers are paying its actual NPSE, less the
sharing band.
The Company's power supply costs and surplus sales are subject to the 95%15% sharing
band, with the Company responsible for 5Yo of the excess NPSE compared to NPSE revenue the
Company collected through base 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 cost. If actual costs are less than revenue collected, the Company keeps 5o/o of that
difference. If costs are more than revenue collected, customers pay 95Yo of the excess costs and
the Company absorbs 5ol0.
1. Forecast Analysis
Based on the forecast as filed, the Company expected to collect $178.8 million from Idaho
customers from June l, 2022, through May 31, 2023. See Brady Direct at 12. Since filing the
PCA, the Company provided updated forecast Bridger production levels resulting in an $8,470,506
reduction in forecast revenue. See Response to Staff Production Request No. 8. The Company
recalculated the forecast portion of the PCA rate with the adjustments to Bridger of 1.13610 cents
per kWh for the 2022-2023 PCA period. With this adjustment, Staff believes the 2022-2023 PCA
forecast is reasonable and any over- or under-collected amounts due to forecast variance will be
trued-up in the following year.
The Company used its March 31,2022, 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 determine and analyze projected load, 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.
Based on information contained in the March Operating Plan, the Company had derated
the amount of power that could be produced from Bridger Units I artd2 due to uncertainty related
to negotiations with the Environmental Protection Agency ("EPA") regarding Regional Haze
regulation compliance. See Brady Direct at 9,10. However, since the filing of the PCA, the
5STAFF COMMENTS MAY t6,2022
Company has become more confident that it will be able to operate these units at higher levels than
originally assumed from encouraging developments in these negotiations. See Response to Staff
Production Request No. 8. As a result, the Company proposes to decrease system NPSE by $9.34
million resulting in a reduction in the amount of revenue it will collect from Idaho customers
through the forecast rate about by $8.5 million.
In its forecast, the Company projects that hydro generation will be lower than average,
market prices for energy will increase, and natural gas prices will increase. With these three
factors, the Company expects to rely on more coal resources and increase sales into the market.
Id. at 12. However, since the Company filed its Application, Staff notes that the snowpack is
approaching near normal levels for most of the Snake River basin. This could cause a reduction
in actual NPSE by allowing the Company to generate more from its hydro units during the
upcoming year; however, Staff believes the impact of the late snowpack development is
insufficient to recommend an adjustment at this time. Staff therefore 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 to
reduce it.
2. Balancing Account Analysis
The Balancing Account incorporates the components of the PCA as shown in Table No. 2
below. Per Order No. 35290, the ending balances of the True-up and the True-up of the True-up
from the previous year's PCA have been included in the calculation. However, going forward,
these elements will no longer be incorporated into the PCA.
Table No. 2: Balancing Account Summarv
Category Amount
1. True-Up Ending Balance from2020-2021PCA
2. True-Up of the True-Up Ending Balance from2020-2021PCA
3. Deferral Balance
4. Forecasted Revenues Collected
5. Collections of the 2020-2021Deferral Balance
6. Interest
2021-2022 Ending Deferral Balance
s4,519,614
(22,156,786)
167,238,783
(128,492,104)
23,408,371
151,647
6
$38,669,526
STAFF COMMENTS MAY 16,2022
Staff s discussion will focus on thc deferral balance for the period of April 2021 through
March 2022 first, followed by the remaining components.
a. Deferral Balance
The defenal balance of $161.2 million includes six different components: (1) the
difference between actual NPSE from April 1,2021 to March 31,2022 and,NPSE recovered
through base rates; (2) the Idaho Jurisdictional Quali$ing Facility Defenal, (3) the Idaho Revenue
Adjustment from the Sales Based Adjustment Rate ("SBAR"); (4) the difference between actual
DR incentive payments and amounts recovered in base rates; (5) the Actual Renewable Energy
Credit ("REC") revenues; and (6) Idaho Power Energy Imbalance Market ("EIM") Participation
Costs.
Based on its review, Staff has confidence that the Company's proposed deferral is accurate,
conforms to past Commission orders, and that costs incurred were reasonable and prudent. Staff s
review included: (i) a review and virtual 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 prudently dispatched resources,
purchased po\A'er, and sold power in the wholesale market.
7STAFF COMMENTS MAY t6,2022
Table No. 3: PCA Deferral Balance Summarv
Deferral Category Deferral Amount
($ 1,652,145)
48,467,294
118,876,260
(27,095,361)
2,261,120
(2,148,489)
$ 138,708,679
$66,032,606
(36,537,349)
(4,140,204)
(5,749,565)
2,924,616
$22,530,104
$161238J83
Table No. 3, above, summarizes the components of the defenal balance. The components
are divided into Net Power Supply Expenses, and Other PCA Expenses. Positive numbers
represent a cost to customers, which would raise the PCA rate on customer bills, and negative
numbers represent a benefit to customers. All amounts are shown after jurisdictional allocation
and the 95%15% sharing band.
i. Net Power Supply Expense Deferral
Staff believes the Company's actual NPSE during the PCA year, April 2021 tfuotgh March
2022, is mostly reasonable; however, Staff discovered an unusually large ambunt of forced
downtime at one of its Units at the Hells Canyon Dam hydro facility. To analyze the prudence of
the Company's actual NPSE, Staff performed two types of review. First, Staff reviewed both
forced and unforced downtime at all Company-owned generation facilities during the PCA year.
Staff believes, actual NPSE could have been lower had the Company avoided excessive downtime
at its Hells Canyon hydro facility. Second, Staff compared the actual amount of generation and
unit cost for the 2021-2022 PCA year and the base NPSE amounts approved in Order No. 33000.
Net Power Supply Expense
Fuel Expense - Coal
Fuel Expense - Gas
Non-Firm Purchases
Off-System Sales / Surplus Sales
Third Party Transmission Expense
Water for Power (Leases)
Subtotal - Net Power Supply Expense
Other PCA Expenses
QualiSing Facilities
Sales Based Adjustment
Demand Response Incentive Payments
Renewable Energy Credit Sales
EIM Participation Costs
Subtotal - Other PCA Expenses
Total Deferral Balance
8STAFF COMMENTS MAY 16,2022
Based on this analysis, Staff believes that the Company dispatched its available resources,
purchased power from the wholesale market, and transacted off-system sales to serve customer
load in a prudent manner.
In response to Staff, the Company stated that Hells Canyon Dam Unit No. 3 ("Unit") went
offline on June 23,2020, due to a phase-to-phase fault with the root cause determined as degraded
coil insulation in the stator. See Confidential Response to Staff Production Request No. 9. The
Unit was scheduled for planned maintenance in August202l with a targeted back in-service date
of February of 2022. Because of the forced outage, the Company decided to utilize the planned
maintenance downtime to repair the stator. The Company was able to pull up the planned
maintenance start date with the contractor to June 1,2021, which allowed an earlier back in-service
date of August2}2l. However, once the Unit was disassembled, additional issues were discovered
requiring additional parts and lead time for delivery. This moved the start date for actual
maintenance to December 18, 2021, and a planned back in-service date of February 2022.
However, the unit did not come online until May I1,2022. The end result left the Unit out of
service for a year before maintenance work began with an additional three months of downtime
after the Unit was projected to return to service. Staff requested the net dollar impact of the
additional downtime beyond what was needed and required, but the Company stated that it would
require additional analysis to determine the overall impact. For this reason and.due to unknowns
and other extenuating circumstances, Staff recommends that the Company work with Staff to
gather additional information, perform analysis, and determine a fair and reasonable outcome for
customers. If warranted, a proposed adjustment could then be included in the balancing account
in next year's PCA for approval by the Commission.
A summary of Staff actual-to-base analysis is provided in Table No. 4, below, on a total
system basis. Expenses reflected in the prior sections are on an Idaho jurisdictional basis.
9STAFF COMMENTS MAY 16,2022
Table No. 4: Actual versus Authorized Net Power Supply Expense Difference
Expense Category
MWh
Change
MWh%
Chanse
s/Mwh
Chanse
$/MWh %
Change
Idaho Power Hydro (3.2s6.346)-38%nla n/a
Acct 501 Coal ( l ,s 17,988)-32%99.92 44%
Acct 547 Other Fuel (Natural
Gas)r.725.898 174%($ 1.74)-5%
Acct 555 Purchased Power
Non-PURPA 2.843.46t 230%($3.31)-7%
Acct 447 Surplus Sales (935.4t7\-41%$36.74 t64%
Acct 555 PURPA 800.824 37%$6.21 t0%
When comparing actual-to-base NPSE, the major drivers affecting NPSE were: (l) reduced
hydro conditions impacting natural gas resources, purchases, and surplus sales; and (2) higher
PURPA related expenses.
Reduced hydro conditions, reflected by the 38% reduction in hydro generation, affected
the Company's NPSE in two ways. First, it forced the Company to rely on other higher cost power
sources, such as natural gas resources and market purchases. This affect is illustrated by the large
increase in MWh for Accounts 547 and 555, which increased by 174% and230o/o, respectively, as
compared to amounts in base rates. However, the unit prices for both accounts were 5-7%o lower
than base numbers, which helped alleviate a larger increase to NPSE. Another factor that
contributes to addition power purchases compared to the base is due to the increased purchases
through the EIM that wasn't implemented when base numbers were determined. Second, reduced
hydro conditions limited the amount the Company could sell into the market resulting in a decrease
in the number of sales, even when the unit price was $36.74lMWh higher than the base price.
PURPA-related expenses were approximately $68 million higher than those reflected in
base rates. These expenses are expected to be higher since the current base NPSE was approved
over eight years ago. The cause of the increase is due to escalating avoided cost'piicing built into
current contracts and from the Company's obligation to take on additional Qualifying Facilities
under PURPA.
As stated above, Staff believes the Company prudently incurred NPSE to meet customer
load. The Company's NPSE primarily consists of costs related to coal and other fuels, non-
PURPA purchased power, and surplus sales. The main NPSE components are described below:
STAFF COMMENTS l0 MAY t6,2022
o Fuel Expense - CoaL The Company has an ownership stake in and receives electricity
from two coal plants. Staff reviewed all months of coal expenses and performed an in-depth audit
for the months of June and November 2021. In the deferral year, actual coal expenses for Idaho
customers were $1.6 million less than the coal expense included in base rates and the previous
forecast, decreasing the deferral balance.
o Fuel Expense - Gas. The Company owns and operates three gas-fired plants. Staff
reviewed all months of the natural gas expenses and performed an in-depth audit for July and
October 2021. The transactions were reasonable and follow the Company's energy risk
management policies and standards. In the deferral year, actual natural gas expenses were $48.5
million more than the expense included in base rates and in the previous PCA forecast, increasing
the deferral balance.
o Non-firm Purchases, The Company buys wholesale power as needed to supplement its
own generation by considering its energy risk management policy, unit availability guidelines, and
market conditions. In addition, the Company's EIM purchases are included as non-firm purchases;
other EIM costs are included as a separate NPSE component. Staff reviewed purchases and
transactions made during the PCA deferral period and they appear to be reasonable and follow the
Company's Risk Management Committee recommendations. These transactions were made with
an assortment of credit-worthy partners in a timely manner. Actual non-PURPA power purchases
exceeded base amounts by $1 18.9 million, increasing the deferral balance.
. Off-$tstem Sales. The Company's revenues from power sales were $27.1 million more
than the amount included in base rates and in the forecast, decreasing the deferral balance.
c Third-ParU Transmission. In OrderNo.30715, the Commission directed the Company
to track third-party transmission costs associated with market purchases and off-system sales
through the PCA. In the deferral year, third-party transmission expenses were $2.3 million more
than the base amounts, increasing the deferral balance.
o Water Leases. The Company incurs lease expenses for water to produce hydro power.
In the deferral year, actual lease expenses were $2.1 million less than those in base rates,
decreasing the deferral balance.
ii. Other PCA Expenses
. Oualif-ying Faciliq)/PURPA Exoense. PURPA contracts are not subject to the 95%15%
sharing band but are subject to jurisdictional allocation between the Company's Idaho and Oregon
STAFF COMMENTS ll MAY 16,2022
customers. For the PCA deferral year, the actual Idaho jurisdictional PURPA expense was $66.0
million above the amount embedded in base rates. This increases the deferral balance to be
recovered from customers.
o Sales-Based Adiustment ("SBA"). The difference in actual and base rate sales is
multiplied by the SBA rate of $26.721MWh, 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 95o/o customer sharing). This year, the Company calculates a $36.5 million
SBA decrease to the deferral balance due to the Company's over-recovery of actual NPSE. Staff
audited andanalyzed the Company's SBA calculations by: (l) auditing actual sales; (2) confirming
the SBA rate and sales used to set base rates; and (3) verifring the Company's method for
calculating the SBA following the 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.
o DR Incentive Pa)tments. The Company's DR incentive payments are not subject to the
sharing band and are wholly allocated to Idaho. Prudency of DR incentive payments will be
determined in the Company's annual Demand-Side Management prudency filing currently before
the Commission (Case No. IPC-E-22-08). 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 2021-2022 PCA deferral balance. Staff confirms that actual DR incentive expenses
in the deferral were $4.14 million less than the amount in base rates. That difference lowers the
deferral balance to be recovered from customers.
o REC Sales. In Order No. 30818, the Commission required the Company to sell all
RECs it receives for renewable generation to benefit its customers. Staff audited the Company's
REC transactions in the PCA defenal 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 $5.7'million.
Currently, REC sales are not included in base rates. These incremental revenues decrease the
deferral balance.
o EIM Participation Costs.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 through the PCA. Including participation costs appropriately matches costs
STAFF COMMENTS t2 MAY t6,2022
with benefits. EIM costs and benefits will be reviewed in the next general rate case when the
Commission will determine which costs and benefits rvill be included base rates. Staff reviewed
EIM participation costs and believes they are appropriately recorded and accurate. Idaho's share
of the EIM expenses is $2.9 million, which is added to the deferral balance.
b. True-Up Ending Balance from 2020-2021PCA
The ending true-up deferral balance from the 2020-2021 PCA period'whs appioved in
Order No. 35054. The ending deferral balance in last year's PCA was $4.5 million. This amount
is added to the beginning balance of the reconciliation of the true-up. Staff verified that this
amount was properly recorded in April 2021 inthe reconciliation of the true-up for recovery. This
is the last True-Up ending balance.
c. True-Up of the True-Up Ending Balance from2020-202lPCA
The remaining balance in the reconciliation of the true-up that was over-recovered in the
previous PCA period is the beginning balance of the reconciliation of the true-up for this PCA
period and was approved in Order No. 35054. This balance of a negative $22.2 million was over-
recovered in the previous period and has been properly recorded in the reconciliation of the true-
up as the beginning balance. This is the last True-Up of the True-Up ending balance.
d. Forecasted Revenues Collected
The Company generated $128.5 million in revenues tiom its PCA Forecast rates during the
current PCA year. Because the forecast rate changes each June, the deferral p'eriod reflects the
rates set in the two previous PCA periods. This amount lowers the overall deferral balance for the
2021-2022 deferral period. Staff verified the revenue that was collected during the PCA period.
e. Collections of the 2020-2021Deferral Balance
Last year's PCA rates collected $23.4 million as authorized in Order No. 35054. Staff
verified that the collection of the deferral balance during the PCA period is correct.
f. Interest
The deferral balance accrues interest at the Commission-approved customer deposit rate of
loh in 2021 and 2022. Staff verified the interest calculations to be accurate. The interest accrued
during the current deferral year is 515I,647 which increases the deferral balance.
3. Revenue Sharing and Rate Calculation
The revenue sharing mechanism, established in 20 I 0 and last modified in Order No. 34071
in 2018, requires the Company to share revenues with customers based on its actual Idaho
STAFF COMMENTS l3 MAY t6,2022
jurisdictional year-end ROE, if it exceeds l0%o. In202l, that ROE was 10.02%o, resulting in
$568,771 in revenue sharing benefit to customers in beginning in June 2022. Staff reviewed the
Revenue Sharing inputs and calculations and agrees with the revenue sharing amount. Staff
believes that the calculation follows the Commission-approved methodology from previous PCA
filings.
The Company proposes to allocate the revenue sharing benefit to customer classes utilizing
the same methodology as in past cases, i.e., based on each class's proportional share of forecasted
base rate revenues for the upcoming PCA rate effective year, which is June 1,2022, through May
31,2023. Each customer class receives a decrease of approximately 0.05 percent relative to current
base revenues. Except for the special contracts, the Company proposes to include the class-
allocated revenue sharing benefits on a cent-per-kWh basis applied to the 2022PcArates effective
June 1,2022, through May 31,2023. Consistent with the methodology used to.share previous
revenues, the Company proposes to provide the special contract customers a flat-dollar-per-month
credit in 12 equal portions to serve as a reduction to monthly invoices billed from June 2022
through }/.ay 2023.
Staff reviewed the components that make up this year's revenue sharing rates and
believes they are reasonable. Staff s review included verification that rates were calculated
accurately, and that the Company's methods comply with Commission orders.
B. PCA Rate Calculations
Staff reviewed the components that make up this year's PCA rates that includes the
adjustment to the forecast rate from the uprating of Bridger availability, which Staff included as
Attachment A to these comments.4 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, including the recent modifications to replace the "true.
up" and the "true-up of the true-up" with a single balancing account. Staff also confirmed that the
revenue requirement was allocated across customer classes on an equal cents per kilowatt-hour
basis, which ensures that customers share the PCA revenue requirement based on the amount of
energy consumed.
a See Attachm ent 2 to Company Response to Staff Production Request No. 8.
5 See Case No. IPC-E-21-18.
STAFF COMMENTS t4 MAY 16,2022
The Company calculated its proposed PCA rate by combining the two PCA components:
forecastpowercostat 1.1361 centsperkWhandbalancingaccountadjustment at0.2579 centsper
kwh. The sum of these components is 1.3940 cents per kwh, which is the rate that was allocated
across all customer classes on an equal cents per kilowatt-hour basis.
C. Notice of PCA Simplification for Future Filings
In Order No. 35290, the Commission approved a modification to the PCA filing to replace
the "true-up" and "true-up of the true-up" with a single balancing account. The two "true-up" rates
previously included in PCA filings are now combined into one o'Balancing Adjustment" rate. The
Balancing Adjustment modification solely impacts the presentment of the PCA but has no material
impact on the rates charged to customers. Going forward, the "true-up" and "true-up of the true-
up" will no longer be referenced in future annual PCA frlings.
D. Overall Impact of Filings Effective June 1,2022
On March 15,2022, the Company filed its annual Fixed Cost Adjustment ("FCA") in Case
No. IPC-E-22-07 , The Company's 2022 FCA filing proposes a $4.9 million decrease in current
billed revenue, or a 0.81 percent decrease, for Idaho Residential and Small General Service
customers, effective June 1 ,2022, through May 31,2023.
On June 3, 2021, the Company applied to increase rates to accelerate the depreciation
schedule of coal-related investments at the Jim Bridger coal-fired power plant ("Bridger") and
establish a balancing account to track the incremental costs and benefits associated with the
Company ending operations there, Case No. IPC-E-21-17. If approved, the request for cost-
recovery from Bridger would increase total billed revenue by $27 .l million-an average of 2.17
percent for aflected customers.
If the PCA, FCA, and Bridger cost-recovery applications are approved as filed, the
combined impact is an overall increase in current billed revenue of $125.6 million, or 10.05
percent. The Company has proposed to implement the PCA, FCA, and Bridger cost-recovery rates
on June 1,2022. The impact by revenue class is:
STAFF COMMENTS 15 MAY t6,2022
Small
General
Service IrrieationResidential
Large
General
Service Large Power
5.24%9.18%12.t0%8.46%6.55%
Proposed 2022-2023 Revenue Impact by Class:
Percentage Increase from Current Billed Rates by Proposed Change
Power Cost ustment
Fixed Cost ustment
Cost-
Total Combined Im
E. 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. The notice was or will be included with bills mailed to
customers beginning April26 and ending May 25,2022. Customers whose bills will be mailed
on May 21,24, and25 were sent a direct mail postcard, mailed no later than May 20, outlining the
Company's filing.
Unfortunately, even with the Company's attempt to provide earlier notice to some
customers, many will not have a reasonable opportunity to file timely comments with the
Commission by the May 16 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 15,2022, the Commission
Residential
Small
General
Service
Large
General
Service Large Power Irrigation
N/A(0.81)%(0.821"N/A N/A
Large
General
Service Large Power IrrisationResidential
Small
General
Service
1.99"/o 2.240 2.23o/o 2.3002.08"h
Small
General
Service
Large
General
Service Large Power IrrigationResidential
11.430 14.330h 10.75.,h7.82"4 6.4loh
STAFF COMMENTS t6 MAY 16,2022
received one customer comment opposing the proposed increase. The customer suggested ways
Idaho Power could save money in lieu of a rate increase.
STAFF RECOMMENDATIONS
Staff recommends that the Commission:
1. Approve the Cornpany's update to Schedule 55 rates, as shown in Company's updated
PCA rate calculation contained in Attachment 2 to the Response to Staff s Production
Request Response No. 8 and also contained in Attachment A to these comments.
2. Order the Company to file an updated Tariff for Schedule 55 rates based on Attachment
A to these comments;
3. Order the Company to work with Staff to gather additional information to determine a
potential adjustment for Hells Canyon Dam Unit No. 3 downtime to be proposed in
next year's PCA.
4. Order the Company to keep Staff and the Commission appraised of the water and
weather conditions affecting the Forecast Rate component, and file for an adjustment
if the forecast changes substantially.
/6L day orMay 2022.Respectfully submitted this
Technical Staff: Kathy Stockton
Travis Culbertson
Michael Eldred
Josh Haver
Robin Maupin
Curtis Thaden
i: umisc/comments/ipce2 l.43dhmlkskttyyrkjh comments
Deputy Attorney General
STAFF COMMENTS t7 MAY T6,2022
For4ast
coal
Water for Power
Gas
Non-PURPA
s coal
Water for Power
Gas
Non-PURPA
3rd Party TEnsmission
I 1S1,179,150
0
79,067,982
98,482,808
5,149,239
2340,s97
33,367,563
62,A16,593
3rd PartyTEnsmission 5,455,955
iurplus Sales {51,735,153}Surplus Sales (55,085,848)
\,let 95% accounts
lifference of Net 95 % accounts
s 160,578,735
1o8,214,il7
Net 95% accounts s 268,193,142
s
\,let 95% rate
(cents per kWh)
0.5552
PCA CATCUTATIONS
305,684,869 TOTAL NPSE
(cents per kwhl
1.13610
0.0751
1.9515
o.0541
3.U2r
-0.0209
1.1705
-0.0209
1.13606
Tariff calculation
(cents per kwh)
SASE 1
= Cells with lnputs
ForEcast - Base 95% SDlit
B6e Forecast
1.0234
8A5E 2
t.7r3t 0.6897 0.6552
0.5018 0.s0180.8531
BASE 3
1.3s49
RecoveEble Portion PCA Forecast (ldaho)
9
$
s
94,227,334 95% Accounts
75,227,25L PURPA
(3,136,355) Demand Response
uqtrsi2r
t70,324,618
1.1361
489,495,300
0.011361
0.002579True-Up
Reveue Sharing
Total PCA Rate
System Sales
ldaho Jurididional S.l6
38,569,525
558,771.00
15,690,545
t4,9,14@6
(cents per kwh)
o.2s79
(centr per kwhl
,,,,:l,i.i,",". rr,, ,' tililE
ldaho Per@ntate
95.559(
133,853,859
78,732,L89
(cents per kwh)
Base
s 212,585,058
s
rate
PURPA
Net 10O% accounts100% accounts
of 100% account
lncentive
77,252,26s
(3,136,35s)
(cents per kwh)
-0.0209
Net 1(X) accounts 8,115,900
100% rate
s
s
Forftast
100% accounts
of 100% account
Attachment A
Case No. IPC-B 22-ll
Staff Comments
0s116122
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 16TH DAY OF MAY 2022,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF
TO rDAHO POWER COMPAIYY, IN CASE NO. Ipc-E-zz-tt, By E-MAILING
A COPY THEREOF, TO THE FOLLOWING:
LISA NORDSTROM
IDAHO POWER COMPANY
PO BOX 70
BOrSE ID 83707-0070
E-MAIL: [e-mail]
[e-mail]
PETER J RICHARDSON
RICHARDSON ADAMS PLLC
515 N 27TH STREET
BOISE ID 83702
E-MAIL: [e-mail]
MATTHEW LARKIN
TIMOTHY TATUM
JESSI BRADY
IDAHO POWER COMPANY
PO BOX 70
BOrSE rD 83707-0070
E-MAIL: [e-mail]
ttatum@idahopower. com
i brady @ idahopower.com
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-MAIL: [e-mail]
Jo,4b"t
SECRETARYf
CERTIFICATE OF SERVICE