20160519Comments.pdf

BRANDON KARPEN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
(208) 334-03s7
IDAHO BAR NO. 7956
Street Address for Express Mail:
472W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
IN THE MATTER OT'THE APPLICATION OF )
IDAHO POWER COMPANY FOR AUTHORTTY )
TO TMPLEMENT POWER COST )
ADJUSTMENT (PCA) RATES FOR ELECTRIC )
SERVICE FROM JUNE I,2016 TRIIOUGH )
MAY 31,2017. )
Ifi$ tllf l9 Ptl
CASE NO. IPC-E-16.08
COMMENTS OF THE
COMMISSION STAFF
t0
,rn Ft,{*r! tAi.,ji l:",i jl,
-., t.. ''i iii i r t* o i Lt ltC
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
The Staff of the Idaho Public Utilities Commission comments as follows on Idaho Power
Company's Application to increase its revenues through the Power Cost Adjustment ("PCA")
mechanism. The comments are divided into four main sections: (1) Summary of Application;
(2) Staff Audit and Analysis; (3) Customer Relations; and (4) Staff Recommendations.
I. SUMMARY OF APPLICATION
On April l5,20l6,Idaho Power Company (the "Company") filed its annual PCA
Application. The Company asks to increase its total revenue by about $17.3 million, or l.57Yo
more than its current billed revenue. The following summarizes the Company's proposal:
STAFF COMMENTS MAY 19,2016
Table 1: Idaho Power Proposed Customer Revenue Impact
Description Currcnt ($) Proposed ($)Differrnce ($) % of increase
PCA Fnture Forecast
PCA True Up (inchrdes reconciliation oftrue-up)
Associated DSM Rider Change
Allocated Revenue Sharing
39,299,591
34,652,303
(3,991,365)
(8,048,717)
47,770,774
38,587,844
(3,970,036)
(3,159,478)
8,471,183
3,935,541
21,329
4,889,239
49o/o
23o/o
0o/o
28o/o
PCA total
Total Billed Revenue
61,911,812
1,103,1 15,547
79,229,104
7,120,432,839
17,317,292
17,317,292
l00o/o
1.570h
As shown above, the Company attributes 49Yo of its proposed $17.3 million revenue
increase to an $8.5 million increase in the PCA future forecast. The remaining increase is due to
a $4.8 million reduction in revenue sharing and a $3.9 million increase in the PCA true-up. A
copy of Company Attachment 2 showing the impact of proposed rates by customer class is
included as Attachment C to these comments. The overall proposed increase is further described
below. The Company proposes that the rate changes take effect June 1, 2016.
A. Proposed PCA Rate Increase
This year, the Schedule 55 PCA rate for each class combines the PCA's three traditional
components (forecast, "true-up," and reconciliation) with two additional components: the
Demand Side Management ("DSM") Rider credit and Revenue Sharing. The five components
are described below.
1. Traditional PCA Components
The traditional annual PCA mechanism has three components: a) a "forecast" or
projection that estimates the difference between net power supply expense ("NPSE") embedded
in base rates and the coming year's NPSE; b) a "true-up" that captures the difference between
actual and base NPSE and credits the revenue from the previous year's forecast rate; and c) a
reconciliation of the prior year's true-up that captures any under-recovered or under-refunded
true-up amount. This is also called the true-up of the true-up.
The Company combines the three traditional PCA rate components to propose a
201612017 PCA rate surcharge of 0.6187 cents per kilowatt-hour (//kwh) (i.e.,0.3422 + 0.3129
- 0.0364). The Company expects this rate will allow it to recover traditional PCA costs in one
STAFF COMMENTS MAY 19,2016
year. The proposed rate is 0.0782 plkwh higher than current PCA rate. Each component is
described in more detail below.
a. Forecast
The Company uses its March 31,2016 Operating Plan to forecast NPSE for the coming
year and determines the difference between these amounts and NPSE embedded in base rates.
The Company reports Idaho ratepayers' share of the difference is about $47.8 million. This
difference is then converted into a llkwh rate by dividing the amount by projected energy sales.
The Company has proposed a 0.3422 f,lkWh forecast rate as compared to a 0.2815 d/kwh rate in
last year's PCA.
b. True-Up
The true-up amount is the difference between: (1) actual and base NPSE, and(2)
revenues from the forecast rate that accrued during the prior year. The prior year's PCA amount
is not precisely recovered, because the expected-cost forecast is never 100% accurate. The
Company converts the true-up amount to a f/kWh rate by dividing it by projected energy sales.
The Company calculates Idaho ratepayers' share of the true-up amount to be $43.7 million, and
expects to recover that amount through a true-up rate of 0.3129 d,lkWh as compared to last year's
rate of 0.2483//kwh. A copy of Company Exhibit 1, which details the Company's true-up
calculations, is reproduced as Attachment A to these comments.
c. Reconciliation of the True-Up
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 revenue-sharing rates against the
amounts set for recovery. Any difference is carried into the next year's true-up reconciliation,
along with the true-up difference. According to the Company, the true-up was over-collected by
about $5.1 million, resulting in a proposed reconciliation of the true-up rate credit of 0.0364
p/kwh as compared to a rate surcharge of 0.0107 (,kWh in last year's PCA.
2. Additional PCA Components
Besides the three traditional components discussed above, this year's PCA includes the
DSM Rider adjustment and Revenue-Sharing components discussed below.
STAFF COMMENTS MAY t9,20t6
a. DSM Rider Adjustment
The Company continuesto apply a $4.0 million DSM fuder credit to the PCA, resulting
in a 0.0284 plkwh rate credit. This revenue credit assures that the change to base level NPSE
approved in March 2014by Order No. 33000 remains revenue neutral. The credit is applied on a
uniform basis to each customer class, and will continue to be included in annual PCAs until
NPSE included in base rates is re-established as part of a general rate case.
b. Revenue Sharing
The Company states its 10.13% year-end Return on Equity ("ROE") will directly reduce
PCA rates by $3.2 million effective June I ,2016, The Company proposes to spread the
Revenue-Sharing amount to the Company's rate schedules on a uniform percent of base revenue
basis, and to assign it to the energy rates in each schedule. This class-specific energy credit
combines the traditional PCA, DSM Rider Adjustment, and Revenue Sharing into one energy
rate for each rate schedule.
B. Company's Rate Calculation
Schedule 55 rates include all the rate changes proposed in this filing. Company Exhibit
No. 2, reproduced as Attachment B in these comments, illustrates the proposed combined
Schedule 55 rates by customer class (column F). It also breaks down the overall Schedule 55
rates by: (1) Revenue Sharing rates in column C, (2) allocated DSM Rider rates in column D,
and (3) traditional PCA rates in column E.
II. STAFF AUDIT AND ANALYSIS
A. Staffs Analysis of PCA Rates
Staff analyzedthe traditional PCA components (forecast, true-up, and reconciliation) and
additional components applied in this case (DSM Rider Adjustment and Revenue Sharing). In
summary, Staff believes that the Company complied with past Commission orders and
accurately calculated all proposed PCA components. Staff s analysis of the PCA components is
as follows.
STAFF COMMENTS MAY t9,20t6
l. Traditional PCA Components
a. The Forecast
The forecast rate accounts for 49Yo, or $8.47 million of the $17.32 million projected
revenue increase from the Company's proposed Schedule 55 rates as illustrated in Table 1 above.
The Company uses its March 31,2016 Operating Plan to forecast the difference between NPSE
embedded in base rates and NPSE the Company expects to recover in the coming year. Table 2,
below, summarizes the differences by account between next year's forecast and current NPSE in
base rates. Staff thoroughly reviewed the Company's Operating Plan, including assumptions
used to develop the forecast. Based on its analysis, Staff believes the Company's forecast
reflects reasonable future conditions, and recommends the Commission accept the new
forecasted PCA rate of $.003422 per kWh.
Table 2: PCA Forecast by Accounts
FERC Account Base NPSE Forecast
95% Sharins Accounts
s 108,503,190 5 t72,127,L06 ss 2,380 597 s -$
S 33,367,563 5 39,202,922 S
Account 555, Purchased Non-PURPA s 62,606,593 s 54,988,467 s
Account 565, 3rd Party Transmission S 5,455,955 5 5,999,4L2 S
Account 447, Surplus Sales S (51,735,153) S (20,930,147) S
Account 501, Coal
Account 530 Water for Power
Account 547, Other Fuel
Difference
3,623,926 s
(2,380,597) 5
5,835,259 s
(7,5L8,t26) 5
543,457 s
30,805,006 s
s/kwh
0.00024
(0.0001s)
0.00038
(0.0004s)
0.00004
0.00200
95% Sharing Accounts Total
100% Shari ng Accou nts
Account 555, PURPA S
Account 555, DR lncentives S
S 1G0,578,735 s 30,808,92s s 0.001998
133,853,869S 158,758,3825 24,9U,513
11,252,26557,401,698S(3,850,567)
0.00170
(0.00028)
s
$
Total s 305,684,869 5 357,547,740 s 51,852,871 s 0.00342
The $51,862,871difference between base NPSE and the forecast is the system revenue
requirement that forms the basis for the forecast portion of the overall PCA rate. When divided
by projected sales over the next PCA year, it results in a0.3422 p/kwh rate.r This increase is
primarily attributed to two factors: (l ) a decrease in forecasted surplus sales, and (2) an increase
in PURPA expenditures.
I The forecast rate uses two sets of forecasted sales to calculate the rate. Demand Response Incentive Payments
differences are divided by forecasted Idaho jurisdictional firm sales, while the PURPA and Non-PURPA differences
are divided by forecasted system firm sales.
STAFF COMMENTS MAY 19,2016
First, the largest increase to the PCA forecast is due to a 60Yo loss in surplus sales
revenue resulting in $30.8 million of lost revenue. The Company explains that lower-than-
expected hydro-generation in the Snake River Basin and lower-than-forecasted market energy
prices primarily drove the reduced sales.
Specifically, the Company states that the Snake River Basin will see forecasted water
increases of nearly 350,000 acre-feet from the previous year. However the Upper Snake River
Basin had reservoir levels roughly 400,000 acre-feet below historical averages when this PCA
year started. Although this year's water conditions are better than last year's, the reservoir
system will still be 50,000 acre-feet short of filling. The result is no flood control releases, and
therefore reduced surplus sales. Further, the Company indicates that lower market purchase
prices result in a forecasted 3loZ reduction in surplus sales volume. The average market energy
sale price for this year's PCA forecast is $ 18.43 per MWh, compared to last year's forecast of
$23.65; a reduction of 22%o. SeeLarkinDl, at 13. Staff calculates thata 3lolo reduction in sales
volume, together with a 22Yo reduction in sales price, puts the forecast of surplus sales at $30.8
million below base NPSE. Staff notes that any changes to the forecast will be trued-up in the
following year.
Second, the Company states that370 MW of PURPA capacity is forecasted to be added
to the Company's system during the PCA year at a cost of $10 million. Staff asked the Company
to provide an update ofinstalled capacity for each project, the scheduled on-line date for each
project, and the current construction status for each project. The Company's response indicated
that only one of the 15 solar projects contributing to the 320 MW of additional capacity is near
completion. Staff notes that although this 40 MW project is nearly complete, it is nevertheless
behind schedule by at least four months. Staff believes it is unlikely that all 370 MW of capacity
will be added this PCA year. Nevertheless, as previously noted, any over or under-collection in
the PCA will be trued-up in the following year. Staff thus believes it is acceptable to include all
forecasted PURPA Account 555 expenses in the PCA forecast. Staff will continue to assess the
monthly PCA Defenal Reports along with the monthly Cogeneration and Small Power
Production Reports to evaluate those solar projects that come on-line during the PCA year. Any
changes to the forecasted PURPA contracts will be trued-up in the following PCA.
STAFF COMMENTS MAY 19,2016
b. The True-Up
The Company's PCA true-up primarily reflects the difference between NPSE collected
through base rates and actual NPSE incurred during the deferral period of April 1,2015 through
March 31,2016. The ending balance also includes collections through the current forecast PCA
rate and monthly accrued interest. Table 3, below, summarizes the $43,661,193 true-up amount
that forms the Company's proposed true-up revenue requirement for Idaho. When divided by
Idaho jurisdictional forecasted sales, it determines the proposed 0.3129 l/kWh true-up rate.
Staff s review of the true-up included: (1) an extensive on-site audit of the various
components included in the true-up or deferral balance; (2) an analysis of the methods and basis
used to calculate the cost deferrals, account balances, and rates; and (3) a review of actual NPSE
including monthly Risk Management Committee minutes, operating plans, and other reports that
were presented to the fusk Management Committee. As a result of its review, Staff believes the
Company's proposed true-up amount and resulting rate are accurate. The methods used conform
to past Commission orders and actual costs incurred are reasonable and prudent.
Table 3: PCA True-Up Summary
Net Power Srpply Expense Differential
Water Leases
Fuel Experse - Coal
FuelExpense - Gas
Stnplus Power Sales
Power Pwchases
Third Party Transmission Expense
78,054
22,276,812
25,993,154
25,675,402
9,577,674
779,433
Subtotal
Renewable Enerry Credit (REC) Sales
94,380,529
(1,630,681)
Subtotal
Amount After Jurisdictional Allocation and Sharing
82,749,848
75,680,834
Sales Based Adjrstnent
Qualifying PURPA Facilities - After Jurisdictional Allocation
(2,955,155)
10,238,596
Demand Resporse Incentive Payments (4,551,152)
Total Expense Items 78,413,123
Reventre from PCA Forecast
Deferral Balance @xpense Items less PCA Forecast Revenre)
Interest on the Deferral Balance
35,020,073
43,393,050
268,143
Total Deferral 43,661,193
STAFF COMMENTS MAY 19,2016
Details of the different components
described below.
51r'o.(ro,ano
,140,C$0,1100
5 120.&)O.000
5100,mo.ujo
sel,om,om
s("l),od),oft)
,4O,O00,O{X)
52.{),0(x,0$J
so
S.2(),o{)(},ofi)
s40,ffx),0fi)
s&),(xx),ou)
in the PCA true-up, as shown in Table 3, are
Net Power Supply Expense Differential
The Company's NPSE primarily consist of costs related to coal and other fuels,
non-PURPA purchased power, and surplus sales. Within the 201512016 PCA year,
reduced availability of hydro generation required the Company to increase power
generation from coal and other fuels, and to increase purchases from non-PURPA
sources. Further, surplus sales declined as a result ofreduced hydro generation, as
well as lower overall market prices. Staff believes the Company prudently incurred
NPSE to meet customer load. The following graph shows the differences between the
base amount, the 201512016 PCA forecast, and the actual expenses for each of these
contributors.
Account Comparisons
@ Base tr 2015-2016 Forecast E 2015-2016 Actual
itr(:(ou11t.!01, (oal Ac(orJnl !.17, Othi)r l:uel Accouilt 551;, purrhrsr,(l Account 4,47, Surplus
Powor Ni$r)..PtlRP/\ Sall? s
The main NPSE components are describe below.
a. Water Leases. The Company may lease water to produce hydro power. The
Company includes the increase or decrease in water lease expense from base
rates in the PCA for recovery from or credit to customers. This year's PCA
deferral balance includes actual water lease expenses of $2,458,651, which is
more than the $2,3 80, 597 of lease expenses included in base rates. The deferral
balance includes the difference of $78,054. This increase in water lease
r_:lEr:Et:l
ffi wmffi W;r;ffiJ
WMffi
STAFF COMMENTS MAY 19,2016
expenses from base expenses is a cost to customers and is subject to
jurisdictional allocation and sharing.
b. Fuel Expense - CoaL Some of the Company's electricity comes from coal
plants. The Company owns an interest in three coal plants: Bridger, Valmy and
Boardman. The Company includes the increase or decrease in coal expense
from base rates in the PCA for recovery from or credit to customers. From
April 2015 through March 2016, the total coal expense for the three plants was
$130,779,992. The total coal expense included in base rates is $108,503,180.
This year's PCA deferral balance includes a difference between costs currently
included in rates and actual costs of $22,276,812. This increase in coal costs
from base costs is a cost to customers and is subject to jurisdictional allocation
and sharing.
c. Fuel Expense - Gas. The Company owns and operates gas-fired combustion
turbine generating plants at the Evander Andrews Power Complex (3 Danskin
units), Bennett Mountain, and Langley Gulch. Staff reviewed the natural gas
purchases in conjunction with the Company's Operation Plan. The transactions
appear reasonable and follow the Risk Management Committee's
recommendations.
From April 2015 through March 2016, the total variable gas and gas
transportation expense for all the gas plants was $59,360,717. The total gas and
gas transportation expense included in base rates is $33,367,563. The PCA
includes this increase in gas expense from base rates. This year's PCA deferral
balance includes a difference between costs currently included in rates and
actual costs of $25,993,I54. This increase in natural gas expenses from base
expenses is a cost to customers and is subject to jurisdictional allocation and
sharing.
d. Power Sales and Purchases. Staff reviewed the Company's power sales and
purchases in conjunction with the Company's Operating Plan. The transactions
appear reasonable and follow the Risk Management Committee's
STAFF COMMENTS MAY t9,2016
recommendations. These transactions were made with an assortment of credit-
worthy partners on a timely basis. The Power Sales and Purchases are
separately discussed below.
(1.) Power Sales. During the PCA year ending March 3l,20l6,the
Company sold off-system surplus power totaling $26,059,751. The total surplus
sales included in base rates is $51,735,153. The PCA includes this decrease in
the power sales from base rates. Actual surplus sales were less than base
amounts by $25,675,402. This revenue decrease is a cost to customers and is
subject to jurisdictional allocation and sharing.
The Company indicates that during the201512016 PCA year,it sold 1.23
million MWh of surplus energy into the market at an average price of $21.26
per MWh. During this same period, the average off-peak Mid-C price for
electrical energy was $20.25 per MWh, while the average peak price was
$25.08 per MWh. This pricing comparison indicates the Company prudently
sold surplus power into the open market. For the 2016/2017 PCA year, the
Company forecasts surplus sales of $ 1 .14 million MWh at an average sales
price of $18.43 per MWh.
(2.) Power Purchases. Excluding PURPA purchases during the PCA year
ending March 31,2016, the Company bought $72,184,267 of power on the
market. The power purchases included the output from the Neal Hot Springs
Power Purchase Agreement, with a25-year levelized contract price of
approximately $117.56/MWh; and the Elkhorn (Telocaset Wind Power
Partners, LLC) Power Purchase Agreement, with a20-year levelized contract
price of approximately $62.38/ltzlWh. Base rates included$62,606,593 in non-
PURPA power purchases. Actual non-PURPA power purchases exceeded base
amounts by $9,577,674. This increase in purchases is a cost to customers and is
subject to jurisdictional allocation and sharing.
The Company purchases non-PURPA power in the wholesale market, as
well as through long-term purchase contracts and exchange agreements. The
average purchase price duringthe201512016 PCA year was $49.47 per MWh.
STAFF COMMENTS l0 MAY t9,2016
This price factors in the cost of third-party transmission. Although this price is
greater than the average Mid-C peak price of $25.08 per MWh, the difference
occurs because some of the Company's existing purchase agreements require it
to buy power for more than the Mid-C peak price, which skews the average cost
of purchased power. These agreements are in place with Telocaset Wind Power
Partners, LLC, USG Oregon LLC, Clatskanie People's Utility, and Raft River
Energy I, LLC.
e. 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 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 April 2015 through March 2016 PCA period, the actual third-party
transmission expense is $6,235,388. The third-party transmission expense
included in base rates is $5,455,955. This year's PCA deferral balance includes
the difference between actual costs and base costs of $779,433. Because the
actual costs are more than the amount included in base rates, this amount
represents a cost to customers. This cost to customers is subject to jurisdictional
allocation and sharing.
ii. Renewable Energy Credit Sales.
In Order No. 30818, the Commission ordered that revenues from the sale of
renewable energy credits ("RECs") should benefit customers. The deferral balance
includes $1,630,681 in revenue from REC sales. After allocation and sharing, Idaho
ratepayers receive $1,478,144 from renewable energy credit sales. This increase in
revenues benefits customers and is subject to jurisdictional allocation and sharing.
iii. Emission Allowance Sales.
In Order No.32424, the Commission ordered that revenues from the sale of
emission allowances, plus any applicable interest, be reflected in the PCA and used to
11STAFF COMMENTS MAY t9,2016
benefit customers by reducing the Company's PCA deferral balance. In the current
PCA period, there were no emission allowance sales.
iv. Sales-BasedAdjustment("SBA").
The Company proposed a $2,955,155 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. This is the first year that the SBA has fully
replaced the Load Change Adjustment ("LCA") used in previous PCAs. See Order
No. 33307 (noting that the SBA will eliminate the line loss bias inherent with using
loads at generation in the LCA).
The SBA uses the $26.721MWh SBA rate established in Order No. 33307 (Case
No. IPC-E-15-15), representing NPSE2 embedded in base rates duringthe2015-2016
deferral period. 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, respectively, than normalized base rate sales (subjectto 95o/o customer
sharing). During the2015-2016 deferral period, actual sales were $116,418 higher
than sales used to set base rates, resulting in a credit back to customers.
Staff audited and analyzedthe 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 was consistent with the
Commission's prior orders. Staff believes the Company calculated the SBA
adjustment consistently with past Commission orders, and that the adjustment is
reasonably accurate in calculating over-recovery of NPSE due to increased sales.
v. OualifringFacilitylPURPAExpense.
For the April 2015 through March 2016 PCA period, the actual Idaho
Jurisdictional PURPA expense is $137,399,772. The Idaho Jurisdictional PURPA
expense included in base rates is $127,161,176. The difference between actual
PURPA expense and base PURPA expense is included in the PCA for recovery from
2 For purposes of the SBA rate, as was the case for the load change adjustment rate (LCAR), NPSE is the energy-
related production cost embedded in base rates. Base energy-related production cost is used to determine the
numerator of the $/MWh rate in establishing these rates. See Order No. 32206 (GNR-E-10-03).
STAFF COMMENTS t2 MAY 19,2016
or credit to customers. In this year's PCA deferral balance, the actual Idaho
jurisdictional PURPA expense exceeded the PURPA expense included in base rates
by $10,238,596. This amount is a cost to customers and increases the PCA deferral
balance. PURPA contracts are not subject to sharing, but they are subject to
j urisdictional allocation.
vi. Demand Response Incentive Payments.
On December 30, 2011, Commission Order No.32426 found the Company's
NPSE to be $208,100,936, which included $11,252,265 of Demand Response (DR)
Incentive payments. Staff has reviewed the $l1,252,265 of DR payments included in
the Company's Base NPSE, and confirms that this figure is correct.
The Company forecasts DR Incentive expenses of $7,401,698 for the2016-
2017 PCA Year, which is $3,850,567 less than the 911,252,265 included in the Base
NPSE. See Larkin DI, Table 1. Staff has reviewed the forecasted DR Incentive
expenses and believes they are reasonable. Further, Staff has confirmed that the
Company has correctly removed $3,850,567 from the 2016-2017 PCA forecast,
which reduces the PCA forecast by 0.0276 cents/kWh. See Larkin DI, Table 4.
Staff also audited the Company's proposed DR Incentive Payment Deferral
balance. Staff confirms there were $6,701,113 in actual DR Incentive expenditures in
the2015-2016 PCA Year, which is $4,551,152 less than the $11,252,265 included in
the Base NPSE. Staff further confirms Company's proposed PCA true-up balance
correctly omits this amount. Staff therefore believes all computations related to DR
Incentives have been accounted for properly.
c. The Reconciliation of the True-up
The reconciliation of the true-up amount is the difference between what was approved to
be collected or refunded when the PCA rate for last year's true-up was set, and what was actually
collected or refunded. The reconciliation of the true-up assures that the amount approved for
recovery is the amount actually recovered. Table 4, below, summarizes the reconciliation of the
true-up for the 2015-2016 PCA period. The $5,073,137 ending balance amount is the revenue
requirement used to form the reconciliation of the true-up portion of the overall PCA rate. When
divided by forecasted Idaho jurisdictional sales, the calculated result is a negative 0.0364 l/kwh
STAFF COMMENTS 13 MAY I9,2OL6
or a rate credit. Staff believes the rate reasonably reflects the amount to be credited to customers
over next year's PCA collection period.
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 the Company correctly reconciled
the true-up.
Table 4: True-Up Reconciliation
20 | 4 -20 I 5 Forecast True- Up
2014-2015 True-Up ofthe True-Up Balance
Revenue Sharing (Order No. 33306 + interest)
DSM Rider Funds (Order No. 33306)
LCA to SBA Adjustrrent (Order No. 33307)
Net Amount Set for Re cove ry(Refund)
Collections from True-Up Rates
Interest
SaknonMwhAdjustrrent (839)
34,515,981
1,484,515
(8,029,177)
(3,970,036)
(1,470,798)
22,529,647
(27,688,442)
85,657
Subtotal
True-Up Reconciliation
The specifics of Staff s review are discussed below.
Q7,602,785)
(5,073,137)
i. 2014-2015 Forecast True-up Balance.
The ending true-up defenal balance from the April2}l4 through March 2015
PCA period was approved in Order No. 33306; Case No. IPC-E-I5-14. The ending
deferral balance in last year's PCA was $34,515,981. This amount is added to the
beginning balance of the reconciliation of the true-up, with recovery set to start in
June 2015 when the PCA rates changed. This amount has been properly recorded in
the month of April 2015 in the reconciliation of the true-up for recovery.
ii. 2014-2015 Reconciliation of the True-Up Balance
The remaining balance in the reconciliation of the true-up that was under-
recovered in the previous PCA period is the beginning balance of the reconciliation of
STAFF COMMENTS 14 MAY 19,2016
the true-up for this PCA period. The amount of $ 1,484,515 was not recovered in the
previous period, and has been properly recorded in the reconciliation of the true-up as
the beginning balance.
iii. Revenue Sharing.
The Revenue Sharing benefit of $8,029,177 was approved in the previous PCA,
Order No. 33306, Case No. IPC-E-I5-14. Staff has verified that this Revenue
Sharing amount is properly reflected in the reconciliation of the true-up.
iv. DSM Rider Funds.
The DSM Rider Transfer was approved in Order No. 33000 and current DSM
rider rates approved in Order No. 33306. The $3,970,036 amount on Line 104 of
Company Exhibit No. 1 represents the collections of the DSM rider portion of current
Schedule 55 rates over the 2015-2016 PCA period. Staff has verified that the
reconciliation of the true-up properly reflects this amount.
v. LCA to SBA Adjustment.
The Company included a$1,470,798 one-time adjustment (credit to customers)
in the reconciliation of the true-up as a result of a Settlement Agreement in which the
parties agreed to change the true-up's LCA to an SBA beginning on January 1,2015.
See Order Nos. 33306 and 33307. Because it was too late to include the methodology
change in the true-up of the 2015-2016 PCA, the Company has included the credit in
this year's reconciliation of the true-up. Staff believes the adjustment complies with
the Commission's orders.
vi. Salmon MWh Adjustment.
The Salmon MWh Adjustment reflects revised generation in the LCAR expense
adjustment. The Salmon MWh Adjustment totals $839 and benefits customers. The
Company provided Staff with confidential workpapers supporting this adjustment.
Staff has verified the calculations and agrees with this adjustment.
STAFF COMMENTS 15 MAY t9,2016
2. Additional PCA Components
a. DSM fuder Adjustment and Transfer
On March 21,2014, the Company increased its base level NPSE by $99.3 million. See
Order No. 33000. This increase causes the Company to collect an extra $3.97 million per year in
DSM Rider funds revenue. Therefore, the Company was to implement the change to base level
NPSE so the change would have no net impact to the overall DSM Rider revenue collected
through customer rates. Id. To maintain "revenue neutrality," the Company implemented a DSM
Rider Ongoing Transfer that removes $3.97 million from the DSM Rider balancing account, and
applies that amount to directly reduce the PCA. Staff has reviewed the treatment of the DSM
Rider Ongoing Transfer and confirms it has been accounted for correctly. The result is a rate of
negative 0.0284 plkwh included in Schedule 55 rates. Staff believes the Company should
continue to include this adjustment in PCA rate calculations until the level of NPSE recovered in
base rates is re-established in a general rate case, or adjusted by Commission order.
b. Revenue Sharing
In 2010, the Commission established a mechanism that required the Company to share
revenue if the Company's actual Idaho jurisdictional year-end ROE exceeded 10.5% in the years
2009 through2011. If Revenue Sharing was triggered, the Company was to share 50% of any
earnings above 105% ROE with customers. See Order No. 30978. For the years ending
December 31,2009 and 2010, Revenue Sharing was not triggered, as the Idaho jurisdictional
year-end ROE was between 9.5Yo and 10.5%. Revenue Sharing was triggered for the years
ending December 3I,2071 and20t2.
The Commission subsequently modified the Revenue-Sharing mechanism and extended
it through 2014. The Commission also reduced the sharing trigger to llYo, with equal sharing
between customers and the Company when the ROE is greater than l0o/o up to and including
10.5%. This customer portion of the "Revenue Sharing" benefit serves as a customer credit that
is netted with the traditional PCA components to yield a combined rate that is set forth in
Schedule 55. In addition, when the ROE exceeds l0.5yo, the earnings above 105% continue to
be shared with customers receivingT5% of the earnings above 10.5%. The customer share of
earnings above 10.5% were applied to the Company's pension balancing account. This
Revenue-Sharing contribution to the pension balancing account reduced the amount the
Company would otherwise be allowed to collect from customers. See Order No.32424.
T6STAFF COMMENTS MAY 19,20t6
In Case No. IPC-E-14-14, the Commission extended the terms of the December 2011
Idaho Settlement Stipulation, with modification, for the period from 2015 through 2019, or until
the terms are otherwise modified or terminated by Commission Order or the full $45 million of
additional Accumulated Deferred Investment Tax Credits ("ADITC") contemplated by the
Settlement Stipulation has been amortized. See Order No. 33149. The provisions of the new
Settlement Stipulation were applied for calendar year 2015 and are reflected in the current PCA
case.
The provisions of the current Revenue Sharing mechanism are:
. The Company's annual Idaho ROE in any year is less than9.5o/o, then the
Company may amortize up to $25 million of additional ADITC to help achieve a9.5%o
Idaho ROE for that year, and may anortize up to a total of $45 million of additional
ADITC over the 2015 through 2019 period.
. If the Company's annual Idaho ROE in any year exceeds l0.0yo, the amount of
earnings exceeding a 10.0o/o Idaho ROE and up to and including a 10.5Yo Idaho ROE will
be allocatedT5% to the Company's Idaho customers as a rate reduction to be effective at
the time of the subsequent year's PCA and 25o/oto the Company.
. If the Company's annual Idaho ROE in any year exceeds 10.50 , the amount of
eamings exceeding a l0.5Yo Idaho ROE will be allocated 50% to the Company's Idaho
customers as a rate reduction to be effective at the time of the subsequent year's power
cost adjustment, 25o/o to the Company's Idaho customers in the form of a reduction to the
pension regulatory asset balancing account (to reduce the amount to be collected in the
future from Idaho customers), and25o/o to the Company.
. If the full $45 million of additional ADITC contemplated by the settlement
stipulation has been amortized the sharing provisions would terminate.
. In the event the IPUC approves a change to the Company's Idaho-jurisdictional
allowed return on equity as part of a general rate case proceeding seeking arate change
effective prior to January 1,2020, the Idaho ROE thresholds (9.5%, l0.0oh, and 10.5%)
will be adjusted prospectively. See id.
For 2015, the Company's jurisdictional ROE was 10.13%. The amount of the
Company's earnings exceeding the ROE of l0%o is $2,565,553. Per the terms of the stipulation,
75%o is shared with customers as a direct reduction to PCA rates, effective June 1, 2016. The
STAFF COMMENTS 17 MAY 19,20T6
customer amount is $1,924,165 and, after tax gross-up, the Revenue Sharing amount to be
flowed through to customers through the PCA is $3,159,478. See Attachment B, column A.
Staff has reviewed the workpapers, source documents and supporting documentation for
the Revenue Sharing calculations and agrees with the Company's filing.
B. Rate Calculations
As noted previously, this year's Schedule 55 rates consist of the traditional PCA
components (forecast rate, true-up rate, and reconciliation of the true-up rate), the DSM Rider,
and Revenue Sharing rates. Attachment B to these comments breaks down the different
components by rate class. Staff thoroughly reviewed all rate calculations and confirmed they are
accurate and comply with past Commission orders. Staff also verified that the basis for the
billing determinants used remains reasonable.
When added together, the three traditional components form the overall PCA rate of
0.6187(,lkWh. See Attachment B, column E. The components have traditionally been calculated
on an equal cents per kilowatt-hour basis to ensure customers share in the credit or surcharge
based on the amount of energy consumed. Staff finds no reason to deviate from past practices.
The Company proposes to credit the roughly $4 million DSM Rider benefit to customers
through arate of 0.0284 l/kwh on an equal cents per kilowatt-hour basis. See Attachment B,
column D. This complies with past Commission orders, and Staffbelieves the rationale for
allowing each customer class to receive credit in the same proportion as established in base rates
remains valid.
The Revenue Sharing credit is allocated based on each class's proportional share of
forecasted base rate revenues for the collection period of June 1,2016 through May 31,2017.
This has been used in previous PCA cases to ensure each class's contribution to the credit is
reimbursed in roughly the same way. The allocations are then distributed in rates on a llkWh
basis for all customer classes except special contract customers. The special contract customers
will receive their benefit through a flat dollar per month credit in 12 equal proportions. See
Attachment B, column C. Staff believes this method remains valid and finds no reason to
deviate from past practices.
STAFF COMMENTS t8 MAY 19,2016
UI. CUSTOMER RELATIONS
The Company filed copies of its press release and customer notice with its Application.
Staff reviewed the documents and determined that both satisfu Commission Rule of Procedure
125, IDAPA 3 1.01.01. 125.
The notice was included with bills mailed to customers beginning April 22,2016. The
last notice will be mailed on May 20,2016, which will allow most but not all customers a
reasonable opportunity to file timely comments with the Commission by the May 19,2016
deadline. Starting March 15, the Company began providing information on its website about its
intent to make its annual PCA filing. After its Application was filed, the website included a
direct link to the Company's PCA press release and customer notice. As of May 19,2016,the
Commission had received four comments from customers. Each customer opposes the proposed
increase.
IV. STAFF RECOMMENDATIONS
Staff recommends that the Commission approve a total deferral amount of $43,393,050
($78,413,123 without 2015-2016 forecast collections) for recovery through Schedule 55 rates as
shown in Staff Attachment B, effective June 1, 2016. Staff further recommends the following:
1. The Commission approve Revenue Sharing amounts proposed by the Company;
specifically PCA revenue sharing of $3,159,478.
2. The Commission approve DSM Rider Transfer Funds of $3,970,036 to be credited to
customers as a reduction.
3. The Commission approve Schedule 55 rates as filed in Attachment I to the Company's
Application.
4. The Company include all attachments and exhibits including any supporting workpapers
in electronic format with all formula intact in the filing of future PCA cases.
STAFF COMMENTS t9 MAY 19,2016
Respecttully submittedthis l4|b dayofMay 2016.
Deputy Attorney General
Technical Staff: Mike Louis
Rick Keller
Kathy Stockton
Patricia Harms
Mark Rogers
Daniel Klein
i:umisc/comments/ipoe I 6.8bkmlrl*lsphmrdk comments
STAFF COMMENTS 20 MAY 19,2016
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Attachment A
Case No. IPC-E-16-08
Staff Comments
0511912016 Page2 of 2
I
3
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ldaho Power Company
Total PCA Rate Calculation
Class Allocated Revenue Sharing and Rider Transfer
State of ldaho
Sales Based Adjustment Rate Methodology
(A)
Rate Allocated
Sch. Revenue
No. Sharing Benefit
(B)
Allocated DSM
Rider (Ongoing)
Transfer
(F)(E)(D)(c)
Li ne
No Tariff Description
. Allocated DSMRevenue Sharine
o"rrrrr "",l*n-
niuer (ongoing)
' Transfer DollarsRateper kWh Rate
Revenue Sharing
PCA per +Ongoing DSM
kWh Rate Rider Transfer +
PCA Rate
Uniform Tariff Rates:
1 Residential Service 1 (S1,39433s) (51,418,213) (0.000280) (So.oooza+1 50.006187 S0.00s6232 MasterMetered Mobile Home Park 3 (51,351) (Sr,+aS1 (0.000267) (50.000284) 50.006187 50.0056363 Residential service Energy watch 4 s0 s0 0.000000 (s0.000284) s0.006187 s0.0059034 Residential Service Time-of-Day 5 (56,445) (S6,efl) (0.000269) (50.000284) 50.005187 50.0056335 Small General Service 7 (546,3821 (532157) (0.0003ss) (SO.OOozaa1 50.006187 S0.00ss485 Large General Service - Secondary 95 (5699,887) (5948,6271 (0.000210) (SO.OmZSal 50.005187 50.0056937 Large General Service - Primary 9P (sAS,SrS1 (s133,156) (0.000183) (sO.OmZA+1 s0.006187 50.0057208 LargeGeneralservice -Transmission 9T (S0zZ1 (S965) (0.000198) (SO.OOOZaal 50.006187 50.0057049 Duskto Dawn Lishting 1s (Sa,asz1 (51,810) (0.000510) (50.000284) 50.005187 S0.ms292
10 Large PowerService - Secondary 19S (51,153) (Sr,SzS1 (0.000182) (SO.OOOZSaI 50.006187 50.00572177 Large PowerService - Primary 19P (53s1,677) (5621,521) (0.0m151) (50.000284) 50.005187 50.00574272 Large Power Service - Transmission 19T (SS,OSa1 (SS,SSa1 (0.0m$4) (SO.OmZAal 50.006187 S0.00s749
13 Agricultural lrrigation Service 24 (SaZO,SOrl (5530,569) (0.000229) (S0.0m284) 50.006187 50.00567414 Unmetered General Service 40 (52,867) ($l,Ztt1 (0.000251) (50.000284) 50.006187 50.005651
1s Street Lighting 47 (Sro,ssE) .57,798]' (0.000389) (S0.0m284) 50.006187 S0.00ss14
76 Traffic Control Lishtins 42 (Ss00) (S8m) (0.000178) (50.000284) 50.006187 S0.00s72s
17 Total Uniform Tariffs (53,032295) (53,723,3021
18 Special Contracts
19 Micron 26
20 JRSimplot 29
2L DOE 30
23 Total Special Contracts
24 Total ldaho Retail Sales
(s68,7s3) (S13454s) NA (so.ooozaal so.oo5187
(so.ooozaal so.006187
s0.00s903
s0.00s903(Szs,s+01 (ss4566) NA(s27,484) (ss7,419) NA (s0.000284) s0.006187 s0.00ss03(s12affi3) (5246,7341
(53,1ss,478) (S3,s70,035)
Note:
( 1) June l, 201.;6 - May 31, 2017 Forecasted Test Year
Attachment B
Case No. IPC-E-16-08
Staff Comments
0s/19/2016
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Attachment C
Case No. IPC-E-16-0g
Staff Comments
05/19/2016
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 19th DAY OF MAY 2016,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF IN
CASE NO. IPC-E.16-08, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
LISA D NORDSTROM
REGULATORY DOCKETS
IDAHO POWER COMPANY
PO BOX 70
BOrSE ID 83707-0070
E-mail : [e-mail]
dockets@idahopower. com
PETER J RICHARDSON
RICHARDSON ADAMS PLLC
PO BOX 7218
BOISE ID 83702
E-mail: oeter(Drichardsonadams.com
MATTHEW T. LARKIN
TIMOTHY E. TATUM
IDAHO POWER COMPANY
PO BOX 70
BOrSE rD 83707-0070
E-mail: [e-mail]
ttatum @ i dahopower. com
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-mail: [e-mail]
CERTIFICATE OF SERVICE