20190515Comments.pdf

MATT HUNTER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMTSSION
PO BOX 83720
BOISE, IDAHO 83720.0074
[phone]
IDAHO BAR NO. 10655
IN THE MATTER OF THE APPLICATION OF
IDAHO POWBR COMPANY FOR AUTHORITY
TO IMPLEMENT POWER COST
ADJUSTMENT (PCA) RATES FOR ELECTRIC
SERVICE FROM JUNE I,2OI9 THROUGH
MAY 31,2019.
RECEIVED
"*ilfi.'1Y l5 PH \:28
=,li#&\Fh\8*'oH
Street Address for Express Mail
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attomey for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
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CASE NO. IPC.E.19.16
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission comments as follows on Idaho Power
Company' s Application.
BACKGROUND
On April 15,2019,Idaho Power Company filed its annual power cost adjustment (PCA)
Application. The Company's PCA Application, if approved, would decrease the revenue
collected by about $50.1 million or 4.34Yo. The Company requested the new rates take effect on
June I ,2019. The Commission first approved the annual PCA mechanism in 1993, and it has
been modified several times since then. See Commission Order Nos. 24806 ,30715,30978,
32206,32424,33149, and 33307. The Company's actual cost to provide electricity (Net Power
Supply Expense, or NPSE) varies from year to year depending on changes in stream flows, the
amount of purchased power, fuel costs, the market price of power, and other factors. The PCA
mechanism tracks annual differences between actual NPSE and NPSE recovered through base
rates. The PCA is also used to provide revenue-sharing benefits resulting from the revenue-
1STAFF COMMENTS MAY 15,2019
sharing mechanism approved in Order No. 33149. Earnings for this PCA year would provide
customers with a revenue-sharing credit. This year's PCA also includes the Company's actual
costs of Western Energy Imbalance Market (EIM) participation as approved in Order No. 34100
and tax reform benefits approved in Order No. 34071.
STAFF REVIEW
If approved by the Commission, this year's PCA filing would decrease Schedule 55
billed revenue by $50.1 million. The decrease includes three components from this year's PCA:
A $50.1 million decrease from the traditional PCA mechanism; a $5.0 million decrease from
revenue sharing under Order No. 33 149; and a total increase of $5.1 million because of
adjustments from the tax reform case (See Order No. 34071).t
These three rate components combine to change Schedule 55 rates by class as
summarized in Table I below:
Table 1: Overall Rate Impact (Excerpted from Company's Application, Attachment 2)
Class Description
Residential
Master Metered Mobile Home Park
Residential Service Time of Day
Residential Service On-Site Generation
Small General Service
Small General Service On-Site Generation
Large General Service
Large Power Service
Irrigation
Micron
JR Simplot
DOE
Unmetered General Service
Street Lighting
Traffic Control Lighting
Rate Schedule No.Change
-3.49%
-3.66%
-3.63%
-3.35%
-2.79%
-2.84%
-4.80%
-6.06%
-4.33%
-6.76%
-7.03%
-6.99%
-4.00%
-2.63%
-5.53%
1
J
5
6
7
8
9
l9
24
26
29
30
40
4t
42
System Average Decrease -4.34"
t The $5.1 million tax reform increase consisted of: (l) A $4.2 million tax reform one-time benefit that was
removed in this year's PCA; and (2) a $0.9 million reduction in OATT-related tax benefits, $3.6 million that was
included in last year's PCA which was reduced to $2.7 million in this year's PCA.
2STAFF COMMENTS MAY t5,2019
Staff audited the Company's sales and costs for the 2018-2019 PCA year, and reviewed
the Company's sales and cost forecasting methodologies for the upcoming2019-2020PCAyear.
Staff also reviewed the Company's filing and methodologies to ensure they complied with the
Commission's prior orders, including orders on revenue sharing and tax reform benefits. Staff
determined:
l. Actual loads, fuel consumption, fuel costs, purchased power costs, and kilowatt-hour
sales for the current PCA year (2018 -2019) are accurate;
2. The Company reasonably forecast kilowatt-hour sales, loads, fuel consumption, fuel
costs, and purchased power costs for the upcoming PCA year (2019-2020);
3. The Company calculated the incremental change in the upcoming year's PCA rates in
compliance with Commission Order Nos. 24806, 307 1 5, 3097 8, 32206, 32424,
33149, and33307;
4. The Company incurred a reasonable and prudent amount of actual NPSE to serve its
customer load;
5. The Company's Idaho jurisdictional year-end Return on Equity (ROE) exceeded the
10.0% ROE threshold for revenue sharing (Order No. 33149), so the2019-2020 PCA
includes a revenue-sharing component and was calculated correctly; and
6. The Company applied the tax reform benefits consistent with Commission Order No.
3407r.
PCA Mechanism
The traditional PCA mechanism is designed to ensure that customers pay no more and no
less than actual NPSE minus customer sharing. The mechanism compares actual NPSE during
the deferral year (April 2018 through March 2019) to NPSE recovered through base rates. If
actual NPSE is higher or lower than the amount recovered through base rates, customers are
surcharged or credited the difference, respectively, minus customer sharing, through Schedule 55
rates.
The traditional PCA mechanism consists of: (l) a forecast of the difference between the
NPSE embedded in base rates and the 2019-2020 projected NPSE; (2) a "true-up" that captures
the difference between actual NPSE and base NPSE that was actually collected in that year and
credits the revenue from the previous year's forecast rate; and (3) a reconciliation of the 2017-
2018 true-up that captures any under-recovered or under-refunded amounts. This reconciliation
JSTAFF COMMENTS MAY t5,2019
is also called the "true-up of the true-up." These components combine for a uniform
0.13 18 p/kwh rate applied across all rate classes.
Forecast Analvsis
Staff believes the 2019-2020 PCA forecast is reasonable, and notes that any over or
under-collected amounts due to forecast variance are trued-up in the following year. The PCA
forecast component to be collected from Idaho customers is $82,706,715. Annis, DI at 15. Staff
verified the forecast portion of the PCA rate and recommends the Commission accept the rate of
0.5836 p/kwh for the 2019-2020 PCA period. Id. at24.
The Company uses its March 29,2018 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 dispatch simulation to analyze projected load, resource balance, and energy
supply to create a monthly forecast for the PCA year. Additional considerations for the forecast
include 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. This year, the Company participated in the EIM, which contributed to an increase in
Forecast Sharing Account 447, Surplus Sales.
Forecasted NPSE expenses are $394,288,927 for the 2019-2020 PCA year, which is an
$8,786,346 decrease from last year. Id. at 8. Table I on page 6 of Mark Annis' testimony shows
the forecasted NPSE is $88,604,058 higher than the base level of NPSE already collected in
rates. The Company took the Idaho jurisdictional share of NPSE differences and adjusted it for
PCA sharing to determine that the PCA forecast component to be collected from Idaho
customers is $82,706,715. Id. at 15.
Accounts Shared at 95% Customers and 5'% Company ("95%o/5o%")
Accounts shared at95o/ol5Yo contain Power Supply Costs and Surplus Sales. The
Commission created a methodology that assigns purchased power costs or benefits to customers
and shareholders as incentive to the Company to make careful resource acquisition decisions. In
the PCA, annual deviations in normalized power supply costs are shared 95%15% by customers
and Company shareholders. Order No. 30715. If costs are below those anticipated, customers
receive 95%o of the difference. If costs are above those anticipated, customers pay 95Yo of the
excess costs and the Company absorbs 5%o.
4STAFF COMMENTS MAY 75,2019
The accounts shared at 95Yo are forecasted to decrease in total by 7 .6%. As a result of the
67Yo forecasted increase in electric market purchase prices, from $16.77 MWh last year to
$35.84 MWh, the Company plans to reduce market and non-PURPA purchases. Annis, DI at 9.
The Company also anticipates increasing coal generation by 29o/o to serve load and contribute to
surplus sales to capture the market opportunity of rising electric market prices. Id. at 13. This is
forecasted to increase coal fuel expense by l7o/o, and increase revenue in sharing accounts above
the prior year by 1500 , which will benefit customers in the next PCA filing. Id. at9-10. The
Company also forecasts that natural gas fuel expense at its gas plants will increase due to an
estimated l9Yo increase in natural gas prices. Last, the Company projects a decrease in hydro
generation as result of reduced snowpack and reservoir storage that will impact inflow to most of
the Company's hydro generation plants. Id. at 14.
Accounts Recovered I 00% from Customers
Accounts recovered at l00oh contain PURPA and Demand Response Incentive expense.
The Company forecasts a 3.8% increase to the accounts recovered at 100%o. Id. at 8. PURPA
energy purchases are expected to increaseby 4%o due to a2%o increase in PURPA generation and
contract price escalation. Id. at l0-l1. Forecasted demand response expenses did not change.
Id. at 10.
True-Up Analysis
Staff s review of the true-up includes: (l) an on-site audit of the components included in
the true-up or deferral balance; (2) an analysis of the methods and basis used to calculate the cost
deferrals and account balances; (3) a review of actual NPSE, including monthly Energy Risk
Management Committee minutes, operating plans, and other reports presented to the Risk
Management Committee; and (4) an analysis to determine if the Company prudently dispatched
resources, purchased power, and sold power in the wholesale market. Based on its review, Staff
believes the Company's proposed true-up amount is accurate, that the methods used conform to
the Commission's past orders, and that actual costs incurred are reasonable and prudent.
The true-up deferral balance, which is shown in Table 2 below, primarily consists of the
differences between actual NPSE and NPSE recovered through base rates, and forecast revenues.
It also includes the participation costs in the EIM, Renewable Energy Credit (REC) sales, and the
difference between actual demand response incentive payments and the amount recovered in
5STAFF COMMENTS MAY 15,20t9
base rates. The ending balance of the true-up also includes collections through the current
forecast PCA rate and monthly accrued interest.
The Company converts the true-up amount to a p/kWh rate by dividing it by projected
energy sales. The Company calculates Idaho ratepayers' share of the true-up amount for a
refund of about $54 million, and expects to refund that amount through a true-up rate of
-0.3806 p/kWh as compared to last year's rate of 0.1398 d/kwh. Table 2, below, summarizes the
Company's proposed $53,933,956 true-up refund amount.
Table 2: PCA True-Up Summary
Net Power Supply Expense Differential
Fuel Expense - Coal
Fuel Expense - Gas
Non-Firm Purchases
Off-System Sales
Third-Party Transmission Expense
Water for Power (Leases)
Deferral Amount
$ 20,666,921
(6,340,692)
21,926,034
(45,386,121)
(t,670,302)
78p29
Subtotal - Net Power Supply Expense
Other PCA Items
Emission Allowances & Renewable Energy Credit (REC) Sales
Sales-Based Adj ustment
Qualifying Facilities
Demand Response Incentive Payments
EIM Participation Costs
$ (10,725,231)
(3,166,495)
(13,212,397)
58,834,175
(4,100,533)
2,951,196
Subtotal - Other PCA Items
Total Expense Items
Revenue from PCA Forecast
$ 41,3i5,946
s 30,580,715
$ (84,316,932)
Deferral Balance (Expense Items less PCA Forecast Revenue)
Interest on the Deferral Balance
$ (53,736,217)
(197,739)
Total True-Up Deferral $__J53J33J50
Details of the different components in the PCA true-up, as shown in Table 2, are
described below. Positive numbers represent a customer cost (recovery from customers), and
negative numbers represent a customer beneht (credit to customers). All amounts are shown
after jurisdictional allocation and sharing.
6STAFF COMMENTS MAY 15,2019
Net Power Supply Expense Dffirential
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. During the 201812019 PCA year, due to higher market
prices and the integration into the EIM markets, the Company has dispatched its thermal
resources (coal and gas units) more than expected, which also increased surplus sales. Coal costs
increased due the higher dispatch. Gas costs would have increased as well, except the
Company's hedging practices benefited customers by about $25 million. All power purchases
through the EIM are recorded as non-firm purchases and, therefore, those expenses have
increased. The main NPSE components are described below.
l. Fuel Expense - Coal. The Company owns an interest in, and receives electricity
from, three coal plants: Bridger, Valmy, and Boardman. Staff reviewed all months of
the coal expenses and performed an in-depth audit for June and November 2018. The
Company includes the increase or decrease in coal expense from base rates in the
PCA for recovery from, or a credit to, customers. From April 2018 through March
2019, the total coal expense for the three plants was $124,832,676. The total coal
expense included in base rates is $103,078,021. This year's PCA deferral balance,
after jurisdictional allocation and sharing, includes a coal expense difference of
520,666,921 for recovery from customers.
2. Fuel Expense - Gas. The Company owns and operates gas-fired combustion turbine
generating plants at the Evander Andrews Power Complex (Danskin), Bennett
Mountain, and Langley Gulch. Staff reviewed all months of the natural gas expenses
and performed an in-depth audit for June and November 2018. The transactions
appear reasonable and follow the Idaho Power Energy Risk Management
Committee's policies and standards.
The Company includes the increase or decrease in natural gas expense from
base rates in the PCA for recovery from, or a credit to, customers. For the 2018-2019
deferral period, the total variable gas and gas transportation expense for all the gas
plants was $25,024,772. The total gas and gas transportation expense included in
base rates is $31,699,184. This year's PCA defenal balance, after jurisdictional
allocation and sharing, includes a gas expense difference of $6,340 ,692 creditto
customers.
7STAFF COMMENTS MAY t5,2019
3. Non-firm Purchases. To supplement its own generation, the Company buys
wholesale power based on its Energy Risk Management Policy and Standards,
operating reserve margins, unit availability, and economics. In addition the Company
has entered the EIM, and all EIM purchases are included as non-firm purchases.
Excluding PURPA purchases during the 2018-2019 PCA year, the Company bought
$82,556,229 of power on the market. Base rates included 559,476,263 in non-
PURPA power purchases. After jurisdictional allocation and sharing, actual non-
PURPA power purchases exceeded base amounts by $21,926,034.
Staff reviewed the purchases, and performed an in-depth audit of select
transactions during the PCA deferral period. Staff compared the term purchase price
to the forward market prices from the monthly operating plans, and compared the
day-ahead and real-time market prices to the Intercontinental Exchange Mid-C daily
price index. The transactions appear reasonable and follow the Risk Management
Committee's recommendations. These transactions were made with an assortment of
credit-worthy partners in a timely manner.
4. O-ff-Svstem Sales. During the 2018-2019 PCA year, the Company's off-system sales
of surplus power totaled $96,923,260. The total surplus sales included in base rates is
$49,148,395. The increase in surplus sales compared to base amounts is driven
primarily by higher market electricity prices, and entering the EIM. After
jurisdictional allocation and sharing, actual surplus sales were greather than base
amounts by $45,386,121; this decreases the deferral balance to be recovered from
customers.
5 . Third-Part.v Transmission In Order No. 3 07 I 5, the Commission directed the
Company to track third-party transmission costs associated with market purchases
and off-system sales through the PCA like other variable power supply costs.
Including transmission expenses in the PCA is a straightforward treatment of power
supply costs that fluctuate with power purchases and sales. For the 2018-2019 PCA
period, the actual third-party transmission expense is $3,424,944. The third-party
transmission expense included in base rates is $5,183,157. After jurisdictional
allocation and sharing, third-party transmission expense decreases the deferral
balance by $1,670,302 and is a credit to customers.
8STAFF COMMENTS MAY t5,2019
6. Water Leases. The Company occasionally leases water to produce hydro power.
There is $2,380,597 included in base NPSE for water leases. Any deviation from the
amount included in base rates either increases or decreases the PCA deferral. This
year the Company entered into one water lease for $2,450,000 ($2,344,650 Idaho
Allocated). After jurisdictional allocation and sharing, $78,929 is an increase to the
deferral balance.
Other PCA ltems
7 . Emission Sales & REC Sales. In Order No. 30818, the Commission required the
Company to sell RECs and apply the benefits to customers. The deferral balance
includes $3,166,495 in revenue from Emission and REC sales, after allocation and
sharing. This increase in revenues decreases the deferral balance recovered from
customers.
Staff reviewed the Emission and REC transactions included in the PCA
deferral period and verified that the amount included in the deferral period is
accurate. Staff notes that the only Emissions Sales of $15.84 occurred in November
2018. Idaho Power has had no emission sales in recent years.
8. Sales-Based Adjustment The Company calculates a$13,212,397 Sales-Based
Adjustment (SBA) credit to customers from the Company's over-recovery of actual
NPSE collected through base rates due to differences in base versus actual sales. The
SBA uses the$26.721MWh SBA rate established in Order No. 33307 (Case No.
IPC-E-15-15). When multiplied by the difference in actual and base rate sales, it
calculates 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 95oh customer sharing).
During the 2018-2019 PCA deferral year, actual sales were 520,501 MWh higher
than sales used to set base rates, resulting in a credit back to customers. 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 followed the Commission's prior orders.
Staff believes the Company calculated the SBA adjustment consistently with past
Commission orders, and that the adjustment is accurate.
9STAFF COMMENTS MAY 15,20t9
9. Ouali.friing Facilitv/PURPA Expense. For the 2018-2019 PCA deferral period, the
actual Idaho Jurisdictional PURPA expense is $185,995,351. The Idaho
Jurisdictional PURPA expense included in base rates is $127,761,776. In this year's
PCA deferral balance, the actual Idaho jurisdictional PURPA expense exceeded the
PURPA expense included in base rates by $58,834,175. PURPA contracts are not
subject to sharing, but they are subject tojurisdictional allocation. Staffaudited the
actual monthly PURPA expense during the defenal period and believes the amount
reported is accurate.
10. Demand Response Incentive Pqtments. Staff reviewed the Company's actual
Demand Response (DR) incentive payments included in the 2018-2019 PCA deferral
balance. Staff confirms there were $7,151,732 in actual DR Incentive expenditures in
the deferral, which is $4,100,533 less than the $11,252,265 included in Base NPSE.
DR incentive payments are allocated l00Yo to Idaho and are not subject to sharing.
The prudency of the DR incentive payments will be determined in Idaho Power's
annual DSM prudency filing currently before the Commission (Case
No. IPC-E-18-03). Any DSM prudency disallowance in that case will be reflected in
next year's PCA deferral balance. This reduced level of DR incentive payments
reduces the deferral balance to be recovered from customers.
ll. EIM Participation Costs. The Company has included operation and maintenance
expenses directly related to its participation in the EIM. The Idaho Power recovery
method for actual costs associated with participating in the EIM, was approved in
Order No. 34100, Case No. IPC-E-I7-16. The benefits of the EIM market
automatically flow through the PCA, matching costs with benefits until the next
general rate case, at which point the costs and benefits will be built into rates. Staff
has reviewed these costs and believes they are appropriately recorded and accurate.
The Idaho share of the EIM expenses is $2,95 7,196.
12. Revenue-from the PCA Forecast The Company's forecast rates generated
$84,3 16,932 in revenue during the deferral period. The forecast rate changes each
June when the new PCA rates are established. Therefore, the deferral period reflects
the rate set in the two previous PCA periods. This amount is credited to customers in
the calculation of the overall deferral balance for the 2018-2019 deferral period. Staff
verified the revenue collected during the PCA period.
STAFF COMMENTS 10 MAY 15,2019
13. Interest on the De-ferual Balance. The deferral balance accmes interest at the
customer deposit rate, which was at l%o for 20 i 8 when it changed to 2o/o for 201 9 per
Order No. 34204. The interest accrued during the current deferral period is a credit to
customers of $197 ,739. Staff verified the interest calculations and agrees with the
Company.
NPSE Analysis
Staff finds that the actual NPSE the Company incurred during the PCA year (April20l8
through March 2019) was reasonable and prudent. To analyze the Company's NPSE, Staff
compared the actual NPSE for the 2018-2019 PCA year and the base NPSE approved in Order
No. 33000. In addition, Staff compared actual NPSE for the 2018-2019 PCA year and the actual
NPSE for the 2017-2018 PCA year. A summary of the analysis is provided in the Tables 3 and 4
below on a total system basis. Expenses reflected in the prior sections are on an Idaho
jurisdictional bases so are less.
Table 3: 2018-2019 Actual NPSE compared to Authorized base NPSE
When comparing actual-to-base NPSE, the major drivers in the difference were PURPA
related expenses and surplus sales. PURPA-related expenses were approximately $61 million
higher than those reflected in base rates. These expenses are expected to be higher since the
Actual versus Authorized NPSE Differences
(Total System)
Expense Category Actual NPSE Base NPSE $ Difference 7o Difference
Acct 501 Coal $ 130,865,930 $ 108,503,180 $ 22,362,750 2t%
Acct 536 Water for
Power (Leases)
$ 2,450,000 $ 2,380,597 $69,403 3%
Acct 547 Other Fuel
(Natural Gas)
$ 26,123,248 $ 33,367,563 s (7,244,315)"\', o/-
Acct 555 Purchased
Power Non-PURPA
$ 86,561,811 $ 62,606,593 $ 23,955,218 38%
Acct 565 Third-Party
Transmission
$ 3,584,536 $ 5,455,955 $ (1,871,419)-34%
Acct 447 Surplus Sales $ ( 101,576,987)$ (51,735,153)$ (49,841,834)96%
Acct 555 PURPA $ 194,969,848 $ 133,853,870 $ 61,115,978 46%
Acct 565 Demand
Response Incentives
$ 7 ,151,732 $ t 1,252,265 $ (4,100,533)
STAFF COMMENTS ll MAY 15,2019
-36%
curent base NPSE was approved five years ago. The cause of the increase is due to escalating
avoided cost pricing built into current contracts and from the Company's obligation to take on
additional Qualifying Facilities under PURPA. Actual surplus sales were 96%higher than base
NPSE, which reduced the total actual NPSE by about $50 million when compared to the base.
Actual surplus sales were significantly higher because higher average market sales price allowed
the Company to take advantage of economic dispatch of coal-fired plants and a higher than
expected hydro generation.
Table 4z 2018-2019 Actual NPSE compared to 2017-2018 Actual NPSE
2018-2019 versus 2017-2018 NPSE Differences
(Total System)
Expense Category 2018-2019 NPSE 2017-2018 NPSE $ Difference 7o Difference
Acct 501 Coal $ 130,865,930 $ 103,318,634 s 27,547,296 27%
Acct 536 Water for
Power (Leases)$ 2,450,000 $$ 2,450,000 nla
Acct 547 Other Fuel
(Natural Gas)$ 26,123,248 $ 33,654,349 $ (7,53 I ,102)-22%
Acct 555 Purchased
Power Non-PURPA $ 86,561,81I $ 64,633,258 $ 21,928,554 34%
Acct 565 Third-Party
Transmission $ 3,584,536 s 4,077,351 $ (492,81s)-12%
Acct 447 Surplus
Sales $ ( 101,s7 6,987\$ (40,633,41s)$ (60,943,573)150%
Acct 555 PURPA $ 194,969,848 $ 186,067,647 $ 8,902,202 5%
Acct 565 Demand
Response Incentives $ 7,151,732 $ 6,983,307 $ 168,425 2%
STAFF COMMENTS t2 MAY 15,2019
When comparing 2018-2019 to 2017-2018 NPSE, the major drivers in the difference
were caused by surplus sales, coal generation, and non-PURPA purchased power. The reason
for a l50o/o increase in surplus sales is the same as previously discussed when comparing actual-
to-base NPSE. Above average market prices allowed the Company to dispatch surplus capacity
into the market. Part of the increase in surplus sales came from the Company utilizing additional
hydro generation from water for power leases which the Company used to sell into the market
during higher priced hours and to avoid high market purchases by using the cheaper water to
meet native load. Higher market prices also allowed the Company to sell more coal generation
into the market as illustrated by the 27o/o increase in coal expense. However, higher market
prices caused purchased power expense (Non-PURPA) to be 34o/ohigher than in last year's PCA.
Part of the increase in purchased power expense compared to last year's PCA was due to
increased purchases through the EIM that wasn't implemented until the beginning of this year's
deferral period.
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 nets the actual revenue collected from the true-up rates. and any other line items collected in
the PCA such as revenue sharing, against the amounts set for recovery. Any difference is carried
into the next year's true-up reconciliation along with the true-up difference. The true-up was
over-collected by about $ 10. 1 million, resulting in a proposed reconciliation of the true-up rate of
-0.0712 p/kwh as compared to a rate of 0.0063 (,lkWh in last year's PCA.
Table 5, below, summarizes the reconciliation of the true-up for the 2017-2018 PCA
period. The $(10,097,124) ending balance amount is the revenue requirement used to form the
reconciliation of the true-up portion of the overall PCA rate. The reconciliation is shown on the
line labeled "Ending True-Up of the True-Up Balance" in Company Exhibit 2.
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. Because of its review, Staff believes the Company correctly reconciled the
true-up. The specifics of Staff s review are discussed below.
Table 5: True-Up Reconciliation
2017-2018 True-Up Deferral (Order No. 34080)
2016-2017 True-Up of the True-Up Ending Balance
Tax Settlement (Order No. 34071)
$ (19,993,280)
(898,592)
(4,244,015)
Net Amount Set for Recovery/(Refund)
Collections from True-Up Rates
Interest
$
$
(25,135,887)
15,282,895
(244,132)
Subtotal
True-Up Reconciliation
$
$
15,038,763
STAFF COMMENTS l3
(10,097,124)
MAY 15,2019
1. 2017-2018 True-up Deferral Balance. The ending true-up deferral balance from the
2017-2018 PCA period was approved in Order No. 24080; Case No. IPC-E-18-06.
The ending deferral balance in last year's PCA was S(19,993,280). This amount is
added to the beginning balance of the reconciliation of the true-up. This amount has
been properly recorded in April 2011 in the reconciliation of the true-up for recovery.
2. 2017-2018 Reconciliation of the True-Up Balance. 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. The
amount of $898,598 was over-recovered in the previous period, and has been properly
recorded in the reconciliation of the true-up as the beginning balance.
3. Tax Settlement. In Case No. GNR-U-18-01, Order No. 34071, the Commission
approved a multi-party settlement where the Company included the tax savings
deferral from January to May of 2018 in the PCA. The $4,244,015 was agreed upon
in the settlement and this one-time reduction is correctly recorded in May 2018 in the
reconciliation of the true-up.
4. 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 properly reflected in the reconciliation of the true-up
Revenue Sharing
The Commission established a mechanism in 2010 that required the Company to share
revenue with customers based on the Company's actual Idaho jurisdictional year-end ROE. See
Order No. 30978. The Commission subsequently modified the revenue-sharing mechanism and
extended it in Order Nos. 32424 and 33149. The terms are effective through 2019, or until
otherwise modified or terminated by Commission Order, or the full $45 million of Accumulated
Deferred Investment Tax Credits are amortized.
The Company's 2018 year-end Idaho jurisdictional ROE was 70.21Yo. The Company's
earnings exceeding the ROE of l}Yois$4,974,987. Per the stipulation,T5o/o is shared with
customers as a reduction to PCA rates, effective June 1, 2019. The customer amount is
$3,731,240, and after tax gross-up, the revenue-sharing amount to be flowed through to
customers through the PCA is55,024,562.
STAFF COMMENTS l4 MAY 15,2019
Staff has reviewed the work papers, source documents, and supporting documentation
and agrees with the revenue-sharing calculations.
Tax Reform Benefits
As part of a settlement stipulation approved in Commission Order No. 34701 in Case
No. GNR-U-18-01, Parties agreed to a $7.8 million PCA credit from June 1,2018 through
May 31,2019. The total tax credit benefits reflect the $4.2 million one-time adjustment
discussed above and an additional $3.6 million credit that will decrease to $2.7 million on
June 1 , 2019 and reach $0 on June l, 2020. See Commission Order No. 34701 at 3. These PCA
credits are associated with tax savings and reduced OATT third-party transmission revenues
agreed to in the settlement stipulation.
Staff reviewed the work papers and supporting documentation, and agrees the tax reform
benefits included in the PCA filing conform to the settlement stipulation.
Rate Calculations
Staff thoroughly reviewed the all the components that make up this year's Schedule 55
PCA rates, which include the traditional PCA mechanism, revenue sharing, and tax reform
benefits, and have concluded that they are fair,just, and reasonable. Staff s review of all the rate
components included verification that: (1) the rates were calculated accurately; (2) the methods
used to spread the rates across the customer classes provided a fair allocation; and (3) the
methods complied with past Commission orders.
For the PCA mechanism, the Company proposes a2019-2020 PCA rate of 0.1318 p/kwh
using a forecast of 0.5836 (lkWh, a true-up of -0.3806 p/kwh, and a -0.0712 AlkWhtrue-up of
the true-up. The Company calculated the overall PCA rate of 0.13 l8 p/kwh by summing the
rates of the three traditional components: the forecast, the true-up, and the reconciliation of the
true-up. Staff confirmed that the method used to allocate the revenue requirement across the
customer classes was done on an equal cents per kilowatt-hour basis. This ensures that
customers share the PCA revenue requirement based on the energy consumed, which is how
NPSE is allocated in customer base rates.
As noted previously, the revenue-sharing amount to be flowed through to customers
through the PCA is $5,024,5 62. The Company proposed to allocate this amount based on the
class's proportional share of forecasted base rate revenues, which is the same methodology used
STAFF COMMENTS 15 MAY 15,20t9
in past cases. This amount will be brought into rates on a cents per kilowatt-hour basis except
for the special contracts, which will use a flat dollar-per-month credit in l2 equal portions. Staff
confirmed the rates were calculated as proposed and believes the method is reasonable.
The tax reform benefits to be received by customer through the PCA for 2019-2020 is
$2,680,957. The Company proposed to allocate this amount to customer classes and bring into
rates using the same methodology as revenue sharing. Annis, DI at33-34. During Staff s
review of the rate calculation for tax reform benefits, Staff found the Company allocated the tax
reform benefits to customer classes the same as revenue sharing, but that the Company did not
bring the class-allocated tax reform benefits into rates in the same manner as revenue sharing for
special contract customers. For special contracts, the Company included the class-allocated tax
reform benefits on cents-per-kWh basis instead of a flat dollar-per-month credit in 12 equal
portions as was done with revenue sharing. While this method differs from how it was described
in testimony, Staff believes this method is reasonable since the benefits are still allocated based
on the class's proportional share offorecasted base rate revenues.
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 meet 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 24 and ending May 23,2019. Customers whose
bills will be mailed on May 20,21,22, and23 were sent a direct mail postcard, mailed by
May 17th, outlining the Company's filing on April 15,2019. Unfortunately, even with the
Company's attempt to notify some customers earlier, many will not have a reasonable
opportunity to file comments by the May l5th comment deadline.
Because the Company is proposing a rate decrease, customers probably will not object to
the proposed rate changes. However, all customers should have an opportunity to comment and
have their comments considered by the Commission. Staff thus recommends the Commission
accept and consider late-filed customer comments. As of May 14,2019 the Commission had
received no comments from customers.
STAFF COMMENTS t6 MAY t5,2019
STAFF' RECOMMENDATIONS
Staff recommends that the Commission:
L Approve the Company's proposed PCA rates as filed, effective June 1,2019.
2. Accept late-filed customer comments.
Respectfully submitted this Itrl day of May 2ot9-
// l)ktr"f t Matt Hunter
Deputy Attorney General
Technical Staff: Michael Eldred
Rachelle Farnsworth
Joe Terry
Johan Kalala-Kasanda
Curtis Thaden
i:umisc/comments/ipce I 9. I 6mhmerfi tjkct comments
STAFF COMMENTS t7 MAY 15,2019
CERTIFICATE OF SBRVICB
I HEREBY CERTIFY THAT I HAVE THIS 15th DAY OF MAY 2019,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF,IN
CASE NO. IPC-E-19-16, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING:
LISA D NORDSTROM
REGULATORY DOCKETS
IDAHO POWER COMPANY
PO BOX 70
BOrSE rD 83707-0070
E-mail : [e-mail]
dockets@idahopower. com
MATTHEW T LARKIN
TIM TATUM
IDAHO POWER COMPANY
PO BOX 70
BOrSE ID 83707-0070
E-mail: [e-mail]
ttatum@idahopower. com
S
CERTIFICATE OF SERVICE