20210518Comments.pdf

JOHN R. HAMMOND, JR.
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720.0074
(208) 334-03s7
IDAHO BAR NO. 5470
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT (PCA) RATES FOR
ELECTRIC SERVICE FROM JUNE I,2O2I
THROUGH MAY 3I,2022
CASE NO.IPC.E.2I.IO
COMMENTS OF THE
COMMISSION STAFF
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Street Address for Express Mail:
I I33I W CHINDEN BLVD, BLDG 8, SUITE 201.A
BOISE,ID 837I4
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
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STAFF OF the Idaho Public Utilities Commission, by and through its Attomey of record,
John R. Hammond, Jr., Deputy Attomey General, submits the following comments.
BACKGROUND
On April 15,2021, ldaho Power Company (the "Company") filed its annual power cost
adjustment ("PCA") Application. The Company seeks an Order approving an update to Schedule
55 reflecting a $39.1 million increase in the PCA rates currently in effect (or an average increase
of approximately 3.36Yo of current billed revenue), effective June 1, 2021 through May 3I,2022.
If approved, the Company's bill to a typical residential customer would increase by about $2.57
per month.
Besides the PCA, the Company recently filed its annual Fixed Cost Adjustment ("FCA")
which, if approved, will impact rates for the same period. Id. at8; see also Case No. IPC-E-2L-03
1STAFF COMMENTS MAY 18,2021
If approved as filed, the proposed PCA and FCA rate adjustments would combine to increase the
Company's current billed revenue by $41.2 million, or 3.55Yo, effective June I ,2021. Id. at9.
STAFF ANALYSIS
Staff recommends approval of the Company's proposed update to Schedule 55 reflecting
a $39.1 million increase in revenue, effective June 1, 2021 through May 31,2022. This
recommendation is based on Staff s audit of sampled transactions, examination of the testimony
and workpapers of Company witness Nicole Blackwell, and Company responses to Staff s audit
requests.
Audit Review
Staff examined the Company's sales and expenses for the historical 2020-2021PCA year
and its forecasting methods, projected revenues, and expenses for the upcoming202l-2022Pc{
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 (2021-2022), the Company's forecast 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 ("NPSE") to serve customers during the current PCA year (2020-2021);
and
3. The Company's Idaho jurisdictional202} year-end Return on Equity ("ROE") of
9.98% is accurate. Since this ROE is under the 10.0% ROE threshold for revenue
sharing set in Order No. 33149, there is not a credit to customers this year.
Components of Proposed PCA Increase
The components of the $39.1 million increase in the PCA are shown in Table No. 1
2STAFF COMMENTS MAY t8,2021
Table No. 1: Revenue Impact bv PCA Rate Comnonent
Rate Component 2020-202t PCA 2021-2022 PCA Difference
PCA Forecast $113,084,635 $126,944,108 $13,859,473
PCA True-up ($42,892,18t)($17,641,954)$25,250,227
Revenue Sharing $0 $0 $0
PCA Total $70,192,455 $109,302,154 $39,109,700
The Company's power supply costs 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 to yearly differences between actual power supply
costs 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 a95Yol5% sharing
band, with the Company responsible for 5o/o of the excess NPSE compared to revenue the
Company collected through base rates. The Commission created this sharing band to incentivize
the Company to make careful resource acquisition and operating decisions. If actual costs are less
than revenue collected, the Company keeps 5Yo of that difference. If costs are more than revenue
collected, customers pay 95Yo of the excess costs and the Company absorbs 5%.
Forecast Anolysis
The Company used its March 25,2021Operating 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 Public Utility Regulatory Policies Act ("PURPA") and non-PURPA contracts.
ln its forecast, the Company projects that hydro generation will be lower than average and
market prices for energy will increase. With these two factors, the Company expects to have
higher power costs at its coal and natural gas plants and fewer market purchases.
3STAFF COMMENTS MAY 18,2021
Based on its forecast, the Company expects to collect $126.9 million from ldaho
customers from June 1,2021through May 31,2022. See Blackwell at 16. The over- or under-
collected amount due to the difference between this forecast and actual revenues and NPSE will
be trued-up in next year's PCA.
True-Up Analysis
The true-up deferral balance of negative $22.1 million includes six different components:
(l) the difference between actual NPSE from June 1,2020 to May 31,2021and NPSE recovered
through base rates; (2) forecasted revenues collected through the PCA since June 1,2020; the
Company's expenses for its participation in the Westem Energy Imbalance Market ("EIM"), (3)
the difference between actual Renewable Energy Credit ("REC") revenues and revenues credited
through base rates; (4) the difference between actual Demand Response ("DR") incentive
payments and amounts recovered in base rates; (5) the difference between actual and forecasted
PCA revenues for the current PCA year; and (6) accrued interest for monthly balances over the
current PCA year.
Based on its review, Staff has confidence that the Company's proposed true-up deferral is
accurate, conforms to past Commission orders, and that costs incurred were reasonable and
prudent. StafPs review included: (i) a review and virtual audit of the true-up 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 power, and sold power in the wholesale market.
Table No. 2, below, summarizes the components of the true-up deferral balance. 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.
4STAFF COMMENTS MAY t8,2021
Table No.2: PCA True-Un Summarv
Deferral Category Deferral Amount
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
Renewable Energy Credit Sales
Sales Based Adjustment
Qualiffing Facilities
Demand Response Incentive Payments
EIM Participation Costs
Subtotal - Other PCA Expenses
Total PCA Expenses
$l1,672,505
19,625,634
26,731,334
-11,917,999
-1,446,799
-1,712,097
$42,952,580
-4,736,347
-18,147,961
65,290,917
-4,697,614
3,026,440
$40,735,435
$83,688,015
PCA Forecasted Revenue
Ending Deferral Balance (Expenses less
PCA Forecasted Revenue)
Interest on the Deferral Balance
Total True-Up Deferral
-105,761,199
-$22,073,184
-83,603
-$22,156,7871
I The "subtotal - Net Power Supply Expense" and "Total True-Up Deferral" amounts in Table No. 2 do not match
their totaled amounts due to rounding.
5STAFF COMMENTS MAY 18,2021
This year's total true-up deferral reduces the PCA balance by $22.1 million, which
reduces the PCA rate by 0.1535 cents per kWh. In last year's PCA, the true-up deferral lowered
rates by 0.222 cents per kwh. Table No. 2 above summarizes the true-up reduction. Specific
components of the true-up are discussed below.
Net Power Supply Expense Deferral
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:
1. Fuel Expense - Coal. The Company has an ownership stake in and receives
electricity from three coal plants. Staff reviewed all months of coal expenses and
performed an in-depth audit for the months of June and November 2020. In the
deferral year, actual coal expenses for Idaho customers were $l 1.7 million more
than the coal expense included in base rates and the previous forecast, which
increases PCA deferral.
2. Fuel Exoense - 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 June and November 2020. The transactions were reasonable and follow
the Company's energy risk management policies and standards. In the deferral
year, actual natural gas expenses were $19.6 million more than the expense
included in base rates and in the previous PCA forecast, increasing the deferral
amount to be collected from customers.
3. Non--firm Purchases. The Company buys wholesale power as needed to
supplement its own generation and to meet the Company's operating reserve
margin requirements 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 found they appear to be reasonable and follow the Company's Risk
Management Committee recommendations. These transactions were made with an
6STAFF COMMENTS MAY 18,2021
assortment of credit-worthy partners in a timely manner. Actual non-PURPA
power purchases exceeded base amounts by $26.7 million, increasing the deferral
balance.
4. Of-f-Svstem Sales. The Company's revenues from power sales were $l 1.9 million
more than the amount included in base rates and in the forecast. This amount
decreases the deferral balance to be recovered from customers.
5. Third-Par\t Transmission. In Order No. 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 $1.4 million less than the base amounts, which
decreases the deferral balance to be recovered from customers.
6. Water Leases. The Company incurs lease expenses for water to produce hydro
power. In the deferral year, actual lease expenses were $1.7 million less than those
in base rates. This amount is deducted from the deferral balance.
Other PCA Expenses
7. 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 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 $4.7 million more than the expected
amount in base rates. These incremental revenues decreased the deferral balance.
8. Sales-Based Ad-iustment ("SBA"l. 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 95Yo customer sharing)
This year, the Company calculates an $18.1 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) verifiing the
Company's method for calculating the SBA following the Commission's prior
7STAFF COMMENTS MAY 18,2021
orders. Staff believes the Company accurately calculated the SBA adjustment and
complied with Commission orders.
9. Oualif.vine Facilitv/PUWA 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 customers. For the PCA deferralyear, the actual
Idaho jurisdictional PURPA expense was $65.3 million above the amount
embedded in rates.
10. DR Incentive Pqtments. 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-21-04). 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 2020-
2021PCA deferral balance. Staff confirms that actual DR incentive expenses in
the deferral were $4.7 million less than the amount in base rates. That difference
lowers the deferral balance to be recovered from customers.
I l. 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 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 base rates. Staff reviewed
EIM participation costs and believes they are appropriately recorded and accurate.
Idaho's share of the EIM expenses is $3 million, which is added to the deferral
balance.
12. Revenue.from the PCA Forecast The Company generated $105.7 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 the two
previous PCA periods. This amount lowers the overall deferral balance for the
8STAFF COMMENTS MAY 18,2021
2020-2021deferral period. Staff verified the revenue that was collected during the
PCA period.
13. Interest on the De-fenal Balance. The deferral balance accrues interest at the
Commission-approved customer deposit rate of 2%o in 2020 and lYo in 2021. Staff
verified the interest calculations and verified that the Company's calculation is
accurate. The interest accrued during the current deferral year is $83,603, which
lowers the deferral balance.
Reconciliation of the True-up (True-up of the True-up) Analysis
The reconciliation of the true-up tracks the recovery of the prior year's true-up amounts.
It compares the revenue collected during the current PCA year (June 1,2020 to May 31,2021)
from the true-up rates to the amount set in the previous year's PCA case. The difference between
actual true-up rates and projected true-up rates is recovered via the reconciliation of the true-up
portion of the PCA rates in the next PCA year (June 1,2021to May 31,2022.)
The Company reported a $4.5 million ending balance for the reconciliation of the true-up,
as shown on the line labeled "Ending True-Up of the True-Up Balance" in Blackwell's Exhibit
No. 2. This year, the combined balance of the true-up and the true-up of the true-up is a credit of
$17.6 million to customers. As shown in Table No. 1 above, this is $25.2 million less than the
$42.9 million credited to customers last year.
Staff audited the amounts booked to the reconciliation of the true-up, verified the
Company's calculations, and reviewed the method used to ensure it complies with past
Commission orders. As a result of its review, Staff believes that the Company correctly
reconciled the true-up. Further specifics of Staff s review are discussed below.
9STAFF COMMENTS MAY 18,2021
Table No. 3: Reconciliation of the True-Un Summarv
Category Amount
Deferral Balances
2019-2020 True-Up Deferral Balance
2018-2019 True-Up of the True-Up Ending Balance
Amount Set for Refund
Revenues
Collections from True-Up Rates
Interest
Revenues Subtotal
-$31,869,646
-10,778,801
-$42,648,447
$47,168,061
True-Up Reconciliation $4,519,614
1. 2019-2020 True-up Deferral Balance. The ending true-up defenal balance from
the 2019-2020 PCA period was approved in Order No. 34682. The ending deferral
balance in last year's PCA was negative $31.9 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 2020 in the reconciliation of the true-up for
recovery.
2 )nt8-2019 Pornnril int n{ tho T-r ro f In Flnl n-no 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.
This balance, $10.8 million was over-recovered in the previous period and has
been properly recorded in the reconciliation of the true-up as the beginning
balance.
3. Collections.from True-up Rates and Interest Staff reviewed and verified the
collections from customers and the interest calculations. Staff has also verified
that the collections and interest are accurately reflected in the reconciliation of the
true-up.
$47,542,201
-374,140
STAFF COMMENTS l0 MAY t8,2021
Revenue Sharing
The revenue sharing mechanism, established in 2010 and last modified in Order No.
34071in 2018, requires the Company to share revenues with customers based on its actual Idaho
jurisdictional year-end Return on Equity (ROE), if it exceeds lloh. In2020, that ROE was
9.98yo, which is below the llYo threshold for revenue sharing. As a result, there is no revenue
sharing benefit to customers in the next PCA year. Staff agrees with its revenue sharing
calculations after reviewing the Company's workpapers, source documents, and other supporting
documentation.
Rate Calculations
The Company calculated its proposed PCA rate by combining the three PCA components:
forecast power cost at $0.8793 cents per kwh, the true-up at -0.1535 cents per kWh, and the
reconciliation of the true-up at 0.0313 cents per kWh. The sum of these components is 0.7571
cents per kwh, which is the rate for all customer classes, and is shown in the Company's
proposed Schedule 55 PCA rates.
Staff reviewed the components that make up this year's PCA rates and has concluded that
they are fair, just, and reasonable. 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 kilowatt-hour basis, which ensures that customers share the PCA revenue
requirement based on amount of energy consumed.
PCA Simplification
The Company's forecast is a substantial cause of the year-over-year variation in the PCA
rate. This variation has resulted in a fluctuation of up to 14.6%o in the annual charges for a typical
residential customer using 800 kWh per month. IPC-E-20-21, Staff Comments at 13. Staff
believes that this variation could be reduced by replacing the forecast with a constant value of
0.5446 cents per kilowatt hour and replacing the true-up and true-up of the true-up with a simple
balancing account. This simplified method would not detract from the intended purpose of the
PCA.
STAFF COMMENTS 11 MAY 18,2021
CUSTOMER NOTICE AND PRESS RELEASE
The Company included a press release and customer notice with its Application. Staff
reviewed the documents and determined that both meet 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 April2T and ending May 26,2021. Customers whose bills will be mailed
on May 22,25, and26 were sent a direct mail postcard, mailed no later than May 21, 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 18th comment deadline.
Because the Company is proposing a rate increase, it is likely that some customers may
object to the proposed rate changes. All customers should have an opportunity to file comments
and have their comments considered by the Commission. Staff thus recommends the
Commission accept and consider late-filed customer comments. As of May 17,202l,the
Commission had received five comments, which were all opposed to raising rates.
STAFF RECOMMENDATIONS
Staff recommends that the Commission approve the Company's update to Schedule 55, as
shown in Attachment 1, effective June 1 ,2021, for the period June l, 2021 through May 31,2022.
Respectfully submitted this of May 2021
Hammond, Jr.
Attomey General
Technical Staff: Brad Iverson-Long
Mike Monison
Johan Kalala-Kasanda
Curtis Thaden
i:umisc:comments/ipce2l. l0jhblmmjkct comments
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STAFF COMMENTS t2 MAY t8,2021
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS l8th DAY OF MAY 2021,
SERVED THE FOREGOING COMMENTS OF TITE COMMISSION STAFF, IN
CASE NO. IPC.E.2I-IO, BY E.MAILING A COPY THEREOF, TO THE
FOLLOWING:
NATHAN GARDINER
REGULATORY DOCKETS
IDAHO POWER COMPANY
PO BOX 70
BOrSE ID 83707-0070
E-MAIL: [e-mail]
[e-mail]
MATTHEW T LARKIN
TIMOTHY E TATUM
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL : [e-mail]
ttatum@ idahopower. com
Y
CERTIFICATE OF SERVICE