20150515Comments.pdf

KARL T. KLEIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 5156
Street Address for Express Mail:
472W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT (PCA) RATES FOR
ELECTRIC SERVICE FROM JUNE I,2OI5
THROUGH MAY 3I,2016,
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO.IPC.E.15.14
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission comments as follows on Idaho Power
Company's proposed rate adjustments. 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 l5,20l5,Idaho Power Company (the "Company") filed its annual Power Cost
Adjustment ("PCA") Application. The Company claims the2015-2016 PCA will decrease its
overall revenue by about $10.1 million (or 0.91%) over current billed revenue. Table I
summarizes of the Company's proposal:
STAFF COMMENTS MAY 15,2014
Table 1: Idaho Power Proposed
Description
PCA without Revenue Sharing
Associated DSM Rider Change
Allocated Revenue Sharing
Mitigation - DSM Rider
Revenue
Revenue Changes
Current
($)
101,549,990
(4,073,117)
(7,780,513)
(16,409,596)
for Idaho Customers
Proposed
($)
(3,970,036)
(7,999,145)
0
75,133,003 (26,416,887)
Difference
($)
103,081
(218,632)
16,408,596
Difference
Total Billed Revenue
Decrease in Bilted Revenue
$73,287,673
1,107,494,402
$63,163,823
r,097,370,552
(l 0,123,850)
(1 0,123,850)
(0.e1,%)
As shown above, the Company's proposal significantly decreases the PCA without revenue
sharing, but expiration of the DSM Rider Mitigation Revenue largely offsets the decrease. The
proposed PCA decrease (including the Company's revenue sharing proposal) is further described
below. The Company proposes that the rate changes take effect June l, 2015.
A. Proposed PCA Decrease
This year the Schedule 55 PCA rate for each class combines the three PCA's traditional
components (forecast, "true-up," and reconciliation) with two additional components (the DSM
rider credit and revenue sharing). These five components are described below.
l. Traditional PCA Components
The traditional annual PCA mechanism has three components: a) a "forecast" or
projection that estimates the difference between power supply costs embedded in base rates and
the coming year's power supply costs; b) a "true-up" that captures the difference between actual
and base power supply costs 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. Each component is
described in more detail below.
STAFF COMMENTS MAY T5,2OI4
A. Forecast
The Company uses its March 26,2015 Operating Plan to forecast power-supply costs for
the coming year. According to the Company, the Idaho ratepayer's share of the difference
between forecasted and base power supply cost is about $39.14 million. The Company converts
the power-supply cost difference to a cents-per-kilowatt hour (l/kWh) rate by dividing the power
costs by projected energy sales. The Company calculates this rate to be 0.2815 P/kWh.
B. True-Up.
The true-up amount is the difference between: (1) forecast and base power-supply costs,
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 I00% accurate.
The Company converts the true-up amount to a fi/kWh rate by dividing that amount by projected
energy sales. The Company calculates the Idaho ratepayer's share of the true-up amount to be
$34.5 million, and expects to recover that amount through a true-up rate of 0.2483 /lkwh.
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. The Company calculates the Idaho ratepayer's share of the
reconciliation of the true-up amount to be $1.5 million, and the rate to be 0.0107f,ikWh.
The Company combines the three traditional PCA rate components to propose a
201512016 PCA rate surcharge of 0.5405 p/kwh (0.2815 + 0.2483 + 0.0107). The Company
expects this rate will allow it to recover traditional PCA costs in one year. The proposed rate is
0.19 l/kwh less than current PCA rates.
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 15,2014
A. DSM Rider Adjustment
The Company continues to apply a $4.0 million DSM Rider credit to the PCA. This
revenue credit assures that the change to base level Net Power Supply Expense ("NPSE")
approved in March 2014 by 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 proposes to share $24.7 million of revenue with customers. This revenue
sharing amount would decrease the PCA by $8.0 million, and the Company's pension balancing
account by $16.7 million. 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 results in a different combined
PCA/ DSM Rider Adjustment/Revenue Sharing energy rate for each rate schedule.
B. Company's Rate Calculation
Company Exhibit No. 2 shows how the Company developed its proposed Schedule 55
rates. Schedule 55 rates include all the rate changes proposed in this filing. Column I shows the
Schedule 55 energy rates proposed by the Company.
II. STAFF AUDIT AND ANALYSN
A. Staffs Analysis of PCA Rates
Staff analyzed the traditional PCA components (forecast, true-up, and reconciliation) and
additional components applied in this case (revenue sharing and DSM Rider Adjustment). In
summary, Staff agrees with all of the Company's proposed PCA components except the true-up.
Staff recommends that the Commission modiff the Company's proposed true-up to reflect the
proposed Settlement in Case No. IPC-E-15-15. Although not yet approved by the Commission,
Staff believes the Commission should include the proposed Settlement's Load Change
Adjustment Rate (LCAR)/Sales Based Adjustment Rate (SBAR) modifrcation in PCA rates here
because the parties have agreed to an adjustment in this case as a provision of the Settlement, and
it would benefit customers by reducing the true-up deferral balance for which they would
otherwise have to pay. Staff s analysis of the PCA components is as follows.
STAFF COMMENTS MAY 15,2014
1. Traditional PCA Components
A. The Forecast
The first traditional PCA component is the forecast component. The Company uses its
March 26,2015 Operating Plan to forecast the difference between the power-supply costs
embedded in rates and the power-supply costs the Company expects to recover in the coming
year. The Operating Plan reflects the most current information available to the Company when it
prepared its filing. The forecast considers many factors, including but not limited to: load, water
conditions, gas hedges, market purchases, transmission availability and the cost of contracts
under the Public Utility Regulatory Policies Act of 1978 ("PURPA"). Throughout the year, the
Risk Management Committee (.'RMC"), consisting of key Company employees, reviews and
updates the Company's risk management strategy. Company Exhibit No I to Mr. Wright's
testimony shows the Company's power-supply expense forecast by account. The table shows
expenses included in Base Rates, Forecasted Expenses, and the Difference. Account 555 -
PURPA Purchase Expense, is shown separately from other Account 555 Non-PURPA Expenses
because the Company does not share differences in PURPA Contract Expenses with its
customers. The Company passes the entire difference in PURPA Qualiffing Facility ("QF")
contracts to customers. I
Attachment A shows Staff s calculation of the PCA rate components. Lines 1 through l8
show the calculation of the forecast rate component. The forecast rate component is the sum of
three rate elements: (l) PCA amounts subject to 9515 sharing; (2) PCA amounts besides demand
expense incentives, that flow to customers without sharing; and (3) the difference between base
and actual demand response incentives. These three rate elements are described below.
The first element is composed of all PCA amounts subject to 9515 sharing. Lines 2
through 8 show this calculation. Line 8 shows the first component of the forecast rate to be
0.2079$lkwh. This rate element captures the effects of expected water conditions, thermal plant
fuel costs and expected market prices that affect power purchases and sales, etc. The primary
drivers of this year's forecast are lower anticipated surplus sales due to lower market prices, and
slightly higher runoff and hydro generation than last year. While runoff volume is expected to be
greater than last year, it is still anticipated to be significantly below average. The net of surplus
' a Qp is a generating facility that qualifies for QF status under PURPA and l8 CFR Part 292 and has obtained
certification of its QF status.
STAFF COMMENTS MAY 15, 2014
sales revenue and generation expense results in an increase of almost $5 million over last i'ear's
forecast.
The second element of the forecast rate component is shown in lines 10 through 12. The
second element includes all amounts, except demand response incentives, which are passed
through to customers without sharing. These amounts are almost entirely PURPA QF contract
costs and total 0.0976 (,lkWh as shown on line 12. PURPA costs are forecast to be almost $14
million higher than last year due to increased generation and higher contract prices.
The third element of the forecast rate component allows the Company to capture the
difference between base and actual demand response incentive payments in the PCA. See Order
No. 32426. The calculation of demand response incentive rates is shown on lines 14
through 16. The difference between these demand response payments and base amounts is
shown on line 16 to be minus 0.0240llkwh. The amount is negative because the forecasted
amount is less than the amount included in base rates.
The Company's forecast for demand response incentive payments is slightly lower in
2015-2016 than in 2014-2015, resulting in a slightly higher customer credit. While Irrigation
Peak Rewards and AC Cool Credit program expenditures should remain relatively stable,
expenditures for the Commercial Flex Peak program could change depending upon the outcome
of Case No. IPC-E-15-03.2 Any variation between forecasted and actual demand response
expenditures will be captured in next year's PCA.
The above three elements combine to produce the PCA forecast rate component of
0.2815 l/kwh shown on line 18. The forecast rate component is significantly larger this year
than it was last year due to a lower expectation of net surplus sales revenue and higher PURPA
expenses. Staff believes the Company's forecast reflects reasonable future conditions. Staff
again points out that any over or under-collected amounts due to forecast error are trued-up in the
following year's PCA.
' In IpC-n- t 5-03, the Company applied to self-manage a commercial demand response program that is similar to the
Company's prior program, which was managed by EnerNoc, Inc. The Commission granted the Application in Order
No. 33292, issued May 7,2015.
STAFF COMMENTS MAY t5,2014
B. The True-Up.
The second traditional PCA component is the "true-up" component. The Company's
filing nets the PCA true-up difference against the amount collected from the application of the
previous year's forecast rate. This difference, with interest, is the PCA true-up deferral balance.
This deferral balance is divided by expected jurisdictional energy sales to produce the true-up
rate component of the PCA.
Page 1, lines 4 through 90 of Company Exhibit No. I calculates a true-up deferral amount
of $34.5 million. To verify revenues and costs associated with the Company's true-up deferrals,
Staff audited the actual revenues and expenses that occurred during the PCA year (April 1,2014
through March 30, 2015). These revenues and costs included water lease expenses, fuel
expenses for coal, fuel expenses for natural gas, power sales and purchases, third-party
transmission expenses, Renewable Energy Credits ("RECs") sales, Emission Allowance sales,
and QF expenses. The Risk Management Operating Plans and Risk Management Committee
minutes were also reviewed.
In addition, Staff verified that the monthly calculated and actual amounts for the revenue
included in the PCA Forecast, as shown on page l, line 7 of Company Exhibit No. I are correct,
and that the megawatt hours used for the Actual Firm Load, as shown on page l, line 10 of
Company Exhibit No. 1 are correct.
The $34.5 million true-up balance, while lower than the prior year's true-up balance, still
indicates that the prior year's forecast was inaccurate. While actual hydro generation was
slightly lower during the PCA year than what the Company had forecast that generation to be,
the difference between the current and prior true-up balances primarily is due to lower than
expected net surplus sales, higher than expected PURPA expenses, and a load change adjustment
rate (LCAR) reflecting lower than anticipated energy sales. The PCA true-up component
includes the following items:
i. Load Chanee Adjustment. This year's true-up calculation includes a positive load change
adjustment of $1 I ,817,280. Actual loads during the true-up year were below normal
loads in 4 months and above normal in 8 months. Overall, the actual load for the PCA
year was below normal by 467,145 MWh. This represents a 3Yo overull decrease in
normalized load. During the PCA year, the monthly increase in loads was less than the
monthly decrease in loads, producing a positive load change adjustment amount.
STAFF COMMENTS MAY 15,2014
The load change adjustment is the product of the positive or negative load growth
and the LCAR of $17.64lMWh for the months of April and May 2014. Beginning June
1,2014, the LCAR increased to $24.34 per Order No. 33000. The LCAR consists of the
energy-classified fixed costs of production embedded in base rates. When load grows,
the adjustment reduces power-supply costs to avoid double counting production costs.
When load declines, the adjustment reimburses the Company for part of its lost fixed
production costs.
The result is that $11,817,280 (before jurisdictional allocation and PCA sharing)
has been added to the deferral balance for recovery from customers in this year's PCA.
This LCAR-related increase is a cost to customers and is subject to jurisdictional
allocation and sharing.
The Settlement proposed in Case No. IPC-E-I5-15 recommends that the
Commission replace the Company's LCAR methodology with a sales-based load
adjustment methodology. Applying a sales-based load adjustment in this case will reduce
the true-up deferral balance. This adjustment will be discussed in more detail later in
these comments.
Water Leases. The Company sometimes leases water from several entities to produce
hydro power. The increase or decrease in the water lease expense from base rates is
included in the PCA for recovery from or credit to customers. This year's PCA deferral
balance includes actual water lease expenses of $ 1,527,000, which is less than the
$2,297,091of lease expenses included in base rates. The deferral balance includes the
difference of $770,091. This decrease in water lease expenses from base expenses
benefits customers and is subject to jurisdictional allocation and sharing.
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
increase or decrease in the coal expense from base rates is included in the PCA for
recovery from or credit to customers. From April 2014 through March 2015, the total
coal expense for the three plants was $139,308,896. The total coal expense included in
base rates is $115,971,408. This year's PCA deferral balance includes a difference
between costs currently included in rates and actual costs of $23,337,488. This increase
in coal costs from base costs is a cost to customers and is subject to jurisdictional
allocation and sharing.
11.
ll1.
STAFF COMMENTS MAY t5,2014
Fuel Expense - Gas. The Company owns and operates gas-fired combustion turbine
generating plants at the Evander Andrews Power Complex (3 Danskin units) and Bennett
Mountain located at Mountain Home, Idaho; and Langley Gulch, located near New
Plymouth, Idaho. Staff reviewed the natural gas purchases in conjunction with the
Company's Operation Plan. The transactions appear reasonable and to follow the Risk
Management Committee's recommendations.
From April2014 through March 2015 PCA, the total variable gas and gas
transportation expense for all the gas plants was $37,702,547. The total gas and gas
transportation expense included in base rates is $35,733,899. The PCA includes this
increase in gas expense from base rates. This year's PCA defenal balance includes a
difference between costs currently included in rates and actual costs of $1,968,648. This
increase in natural gas expenses from base expenses is a cost to customers and is subject
to jurisdictional allocation and sharing.
Power Sales and Purchases. Staff reviewed the Company's power purchases and sales in
conjunction with the Company's Operating Plan. The transactions appear reasonable and
to follow the Risk Management Committee's recommendations. These transactions were
made with an assortment of credit-worthy partners on a timely basis, and there were no
transactions conducted with a Company affiliate.
a. Power Sales. During the PCA year ending March 31,2014, the Company sold
off-system surplus power totaling $59,257,485. The total surplus sales included
in base rates is $61,373,402. The PCA includes this decrease in the power sales
from base rates. Actual surplus sales were less than base amounts by $2,1 15,917.
This revenue decrease is a cost to customers and is subject to jurisdictional
allocation and sharing.
b. Power Purchases. Excluding PURPA purchases during the PCA year ending
March 31,2015, the Company bought $81,170,256 of power on the market. The
amount of non-PURPA power purchases included in base rates is $60,063,512.
Actual non-PURPA power purchases exceeded base amounts by $21,106,744.
This increase in purchases is a cost to customers and is subject to jurisdictional
allocation and sharing.
lv.
v.
STAFF COMMENTS MAY T5,2OI4
vi. Third-Party 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 2014 through March 2015 PCA period,
the actual third-party transmission expense is $6,046,383. The third-party transmission
expense included in base rates is $5,91 I ,977. This year's PCA deferral balance includes
the difference between actual costs and base costs of $234,406. 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.
vii. Hoku First Block Energy. In Order No.32426 (Case No. IPC-E-I l-08), the Commission
determined that the Company should include first block energy revenue from Hoku in
base rates like secondary sales revenue. The PCA tracks the variation between the
amount of Hoku revenues built into base rates and the actual Hoku revenues. The
amount of Hoku revenues included in base rates is $3,216,534. The actual amount of
Hoku revenues during the current PCA period is $0. New base rates, beginning in June
2014, set in Order No. 33000, Case No. IPC-E-I3-20, no longer include Hoku revenues.
For the months of April and May 2014, the actual Hoku revenues are less than the
amount included in base rates by $3,216,534. This revenue decrease is a cost to
customers and is subject to jurisdictional allocations and sharing.
viii. 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 benefit customers by reducing the Company's PCA deferral balance, subject to
jurisdictional allocations and sharing. In the current PCA period, the deferral balance
includes emission allowance sales of $16,250. This revenue increase benefits customers
and is subject to jurisdictional allocation and sharing.
ix. Renewable Enersy Credit Sales. In Order No. 30818, the Commission ordered that
revenues from the sale of renewable energy credits ("RECs") should benefit customers
and be subject to jurisdictional allocation and sharing. The deferral balance includes
$2,400,487 in revenue from REC sales. This increase in revenues is a benefit to customer
and is subject to jurisdictional allocation and sharing.
STAFF COMMENTS 10 MAY 15,2014
x.Actual PURPA Purchases Includins Net Metering and Raft River Expenses. For the
April2014 through March 2015 PCA period, the actual PURPA expense is
$147,105,350. The PURPA expense included in base rates is $123,784,522. The
difference between actual PURPA expense and base PURPA expense is included in the
PCA for recovery from or credit to customers. In this year's PCA deferral balance, the
actual PURPA expense exceeded the PURPA expense included in base rates by
$23,320,828. This amount is a cost to customers and increases the PCA defenal balance.
PURPA contracts are not currently subject to sharing, but they are subject to
j urisdictional allocation.
Demand Response Incentive Payments. In Order No.32426 (Case No. IPC-E-I1-08), the
Commission determined that the Company must include Demand Response Incentive
Payment expenses in base rates and track differences between base expenses and actual
expenses through the PCA. Idaho Demand Response Incentive Payments are directly
assigned to Idaho and are not subject to sharing. For the PCA period (April 2014 through
March 2015), the actual Demand Response Incentive Payments are $7,946,728. The base
amount of Incentive Payments included in base rates during the PCA period is
$11,208,367. The difference between the actual amount and the base amount is
$3,261,639, and is a benefit to customers. The Demand Response Incentive Payments
are not currently subject to sharing and are allocated 100% to the Idaho jurisdiction.
Table 2 summarizes the PCA's true-up deferral balance:
xt.
Table 2: True-Up Deferral
Description
Load Change Adjustment
Water Leases
Fuel Expense - Coal
Fuel Expense - Gas
Surplus Sales
Non-Firm Purchases
Third Party Transmission Expense
Hoku First Block Revenue
Deferral
Amount
$11,817,280
(770,091)
23,337,488
r,968,648
2,115,917
21,106,744
234,406
3,216,534
Subtotal
STAFF COMMENTS 11
63,026,925
MAY 15,2014
Emission Allowance Sales Credits (t6,250)
Renewable Energy Credit (REC) Sales (2,400,487)
Subtotal
Amount After Jurisdictional Allocation and Sharing
Qualiffing Facilities - After Jurisdictional Allocation
60,610,189
54,700,695
22,154,787
Demand Response Incentive Payments (3,261,639\
Total Expense Items
Revenue from PCA Forecast
Deferral Balance
Interest on the Deferral Balance
73,593,843
39,275,784
34,318,059
197,922
Total Deferral $34,515,981
The Company proposes a 0.2483 l/kwh true-up rate. Staff agrees that the Company's
calculations are correct but recommends that the true-up deferral balance be reduced by $ I .471
million to reflect Settlement Agreement terms submitted to the Commission in Case No.
IPC-E-15-15.
The Company accepts Staffls proposed $1.471 million true-up adjustment in this case,
and that adjustment has been incorporated in the Settlement Agreement filed with the
Commission on May 2,2015, in Case No. IPC-E-I5-15. The main change proposed in the
Settlement Agreement is to modiff the PCA to track the difference between Idaho actual sales at
meter and Idaho base sales at meter (sales based adjustment- SBA), rather than the difference
between base system load at generation and actual system load at sales (load change adjustment-
LCA). This solution addresses the "line loss" inaccuracy identified by Staff in last year's PCA.
Although the Commission has not yet approved the Settlement Agreement proposed in
the other case, that Settlement Agreement specifies that the new methodology should apply to
the PCA true-up calculation beginning on January 1,2015 and incorporated in the 2015-2016
PCA (this case). Moreover, in Order No. 33049 and again in Order No. 33089, the Commission
directed the parties to hold workshops and conduct informal discussions regarding modifications
to the PCA to improve its accuracy. The Settlement Agreement and the recommended true-up
adjustment in this case are the result of those discussions.
The adjustment results in a true-up rate of 0.2376 //kwh. The Company's rate
calculation with the Staff adjustment is shown on Staff Attachment A, Lines 23 through26.
STAFF COMMENTS T2 MAY 15,2014
C. The Reconciliation of the True-up
The third traditional PCA rate component is the "reconciliation" component. 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 the Company and its customers that the
amount approved for recovery is the amount actually recovered.
Staff audited the amounts booked to the Reconciliation of the True-up, including the
revenue sharing and the transfer of the deferral balance from the previous PCA year, and verified
that the actual monthly collections and interest calculations are correct.
Table 3 summarizes the PCA's true-up reconciliation:
Table 3: True-Up Reconciliation
2012-13 Forecast True-Up
20ll-12 True-Up of the True-Up Balance
Revenue Sharing (Order No. 32821 + interest)
Net Amount Set for Recovery/(Refund)
Collections from True-Up Rates
Interest
DSM Rider Funds (Order No. 33049) (20.000.000)
$58,088,876
19,140,917
(7,624,233)
49,605,560
(48,414,394)
293.349
Sub-Total
True-Up Reconciliation
(28,172,62t)
$ 1,484,5 15
Staff and the Company both recommend that customers recover this amount. Dividing
this amount by expected sales produces the true-up reconciliation rate of 0.0107 l/kWh. This
calculation is shown on Attachment A, line 28.
With the SBAR credit, Staff calculates the sum of all three PCA rate components to be
0.5298 llkwh rather than 0.5405 l/kwh as proposed by the Company. Staff s recommended rate
is shown on Attachment A, line 31.
STAFF COMMENTS 13 MAY 15,2014
2. Additional PCA Components
A. DSM Rider Adjustment
Staff has reviewed the Companies allocation of the ongoing $4.0 million DSM RiCer
credit to the PCA. This revenue credit assures revenue neutrality associated with base rate
changes approved by Order No. 33000. Staff confirms that the credit is applied on a uniform
basis to each customer class to reduce billed revenue by 0.0286 P/kWh or 0.39%o of billed
revenues.
B. Revenue Sharing
In 2010, Commission Order No. 30978 established a mechanism that in part required the
Company to share revenue if the Company's actual Idaho jurisdictional year-end Return on
Equity (ROE) exceeded 105% in the years 2009 through 2011. If revenue sharing was
triggered, the Company was to share 50o/o of any earnings above 10.5% ROE with customers.
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 andl0.5%. Revenue sharing was
triggered for the years ending December 3l,20ll and20l2.
Order No.32424 modified the revenue-sharing mechanism and extended it through2}l4.
Order No.32424 reduced the sharing trigger to l0o/o, with equal sharing between customers and
the Company when the ROE is greater than llYo 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 receiving 75oh of the earnings above 10.5%. The customer share of earnings above
10.5% will be applied to the Company's pension balancing accounts. This revenue-sharing
contribution reduces the amount the Company would otherwise be allowed to collect from
customers.
In Case No. IPC-E-14-14, the Commission approved extending, with modif,rcation, the
terms of the December 2011 Idaho settlement stipulation 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 ADITC contemplated by the settlement stipulation has been amortized. The
provisions of the new settlement stipulation will be applied for calendar year 2015 and reflected
in the next PCA.
STAFF COMMENTS MAY t5,2014
In this year's filing, the Company proposes to share $24.7 million of revenue with
customers. The offset to the PCA is $8 million, and the remaining $16.7 million is to be applied
to the Company's pension balancing account. The Company proposes to spread the PCA
revenue-sharing credit to customer classes based on each class's proportional share of the
forecasted base revenue for the year begiruring June 1,2015. The Company has used this
methodology to allocate revenue sharing in prior years. Staff has reviewed the workpapers,
source documents and supporting documentation for the revenue sharing calculations and agrees
with the Company filing.
The Company proposes that each special contract customer receive a different, flat-
monthly credit during the PCA year. The proposed credits for the special contract customers are:
Micron - $14,629.27; Simplot - $5,656.11; and Department Of Energy - $6,528.59 (Company
Attachment 1). These rates are included in Tariff Schedule No. 55, which is proposed to be
effective June I ,2015, and remain in effect for one year.
B. Staffs Rate Calculations
The derivation of traditional PCA rates is shown on Attachment A to these
comments. The uniform 0.5298//kYyh PCA rate surcharge is the sum of the three traditional
PCA components (0.2815 + 0.2376 + 0.0107) designed to collect an NPSE amount of $73.67
million. The new PCA surcharge rate also includes the true-up adjustment proposed in Case No.
IPC-E- l 5- 15, and reflects the agreed-upon use of an SBAR rather than an LCAR. The overall
rate is significantly less than the current rate of 0.7304 i,/xWh.
The revenue-sharing rate decrease of approximately $8.0 million is spread to the
individual rate schedules on an equal percentage ofbase revenue basis. The rate spread reduces
current base revenue to all schedules by 0.78 Yo. The reduction is credited through the energy
rates of each schedule. This process creates a different rate for each schedule. Finally, the $4.0
million in DSM rider funds that accrue to the rider account each year is a direct result of the base
rate increase approved in Order No. 33000. The credit is allocated to each customer rate
schedule on an equal p/kwh basis for an overall rate decrease of 0.0286 (,lkWh and an overall
decrease in current base revenue of approximately 0.39%.
Attachment B shows the revenue-sharing allocation and the DSM credit by customer rate
schedule, and Attachment C shows Schedule 55 rate components by customer class. The rate
components are the same as those proposed by the Company, except for the traditional PCA that
STAFF COMMENTS 15 MAY 15,20t4
includes the SBAR true-up adjustment. The reduction in billed revenue by customer rate
schedule is shown on Attachment D, as is the overall reduction of $ 1 1 .6 million or | .05o/o.
III. CUSTOMER RELATIONS
A. Customer Notice And Press Release
The Company filed copies of its press release and customer notice with its Application.
Staff reviewed both documents and determined that they comply with the Commission's
Procedural Rule 125, IDAPA 3 1.01.01.125.
The customer notice was mailed with cyclical billings beginning April23 and ending
}lf.ay 21. This means that many customers will not receive notice of the case until after the
comment filing deadline of May 15,2015. Other customers who receive notice on or shortly
before the comment deadline will not have a reasonable opportunity to prepare and file timely
comments. Staff is concerned that many customers will not receive timely notice of the
Company's Application. Staff does not believe customers will object to a decrease in the PCA,
but recommends that the Commission accept late-filed comments, recognizing the probability
that the Commission will be unable to take into consideration comments filed by customers
whose bills are issued at the end of the billing cycle.
B. Customer Comments
As of May 14,2015, the Commission has received no comments from customers.
IV. STAFF RECOMMENDATIONS
Staff recommends that the Commission approve the Company's proposed PCA rates
as modified to include the SBAR true-up adjustment. Staff further recommends that the
Commission approve the Company's proposed revenue-sharing amounts; specifically, PCA
revenue sharing of $7,999,145 and a pension balancing account contribution of $16,693,134.
Staff also recorlmends that the $4 million in energy efficiency tariff rider funds be credited to
customers as a reduction in the201,5-2016 PCA.
Staff recommends that the Commission approve Schedule 55 rates as shown in Staff
Attachment D. Staff further recorrmends that new base rates and updated Schedule 55 rates be
effective June l, 2014.
STAFF COMMENTS t6 MAY t5,2014
Respectfully submitted this lr+L day of May zor4.
4ul4-
Karl T. Klein
Deputy Attorney General
Technical Staff: Randy Lobb
Kathleen Stockton
Daniel Klein
I:\umisc/comments\ipcc I 5 . I 4kkrlklsdk comments
STAFF COMMENTS t7 MAY 15,2014
2015-2016 PCA - Twenty Third Annual
tPc-E-15-14
Staff Case
(a)
Line
(c)
Units
(s)
(s)
(s)
(%)
($)
(MWh)
(c/kwh)
(s)
(MWh)
(c/kwh)
(s)
(MWh)
(c/kwh)
(c/kwh)
(b)
Description
1 Forecast 2014-2015
PCA Expense (95%)
Hoku First Block Revenue
Difference
Sharing Percentage
Shared Difference
Normalized System Firm Sales
Rate for 95% ltems
PCA Expense (PURPA at 100%)
Normalized System Fiirm Sales
Rate For PURPA
Demand Response lncentives (100%)
ldaho Jurisdictional Sales
Rate for Demand Response
18 Total Forecast Rate
19
20
2L
22
23 True-Up of 2014-2015:
28 True-Up of the True-Up:
29
30 PCA Rates:
(e)(f)(e)(d)
2
3
4
5
5
7
8
9
10
11
t2
13
t4
15
16
17
Base
L60,578,735
t92,408,459
133,853,869 748,054,626
1,L,252,265 7,927,041
rs)(MWh)
34,515,981 L3,907,424
(t,470,798) t3,901,424
33,04s,183 L3,901,424
L,484,5t5 13,901,424
Forecast Difference
L92408459
0
37,829,724
0.95
30,238,238
L4,545,294
0.2079
14,200,757
14,545,294
0.0976
(3,33L,2241
L3,90t,424
(o.o24o)
(s/MWh)
0.2483
(0.0106)
0.2377
0.0107
Rate
o.2079
0.0976
(0.0240)
0.2815
(c/kwh)
0.2483
o.2377
0.0107
0.5298
0.7305
(o.2oo7)
24
25
26
27
Company Proposal
SBAR Adjustment (Case No. IPC-E-15-15)
Staff Proposal
31
32
33
34
PCA Rate Adjustment From Base
PCA Rate Currently in Effect
Difference - Last Year to This Year
(c/kwh)
(c/kwh)
(c/kwh)
35 Note: Negative rates and amounts indicate benefit to ratepayers
36
37
38 Expected PCA Revenues
39
40
Forecast Revenues
True-Up Revenue
True-Up of the True Up Revenue
Tota I
47
Notes: Rates for one year recovery period
Rates exclude Revenue Sharing and DSM Rider credit
0.s298 73,662,207
L3,901424 Company Forecast of 20L5/20t6ldaho Jurisdictional sales
L4,545,294 Company Forecast of 20t5l2Ot5 Normalized System Firm Sales
Attachment A
Case No. IPC-E-I5-14
Staff Comments
0sllslr5
Rate
(s/MWh)
Energy
(MWh)
2.815 73,901,424
2.377 13,901,424
0.107 13,901,424
Revenue
6)
39,132,509
33,045,183
1,484,515
41
42
43
44
45
46
as(n o)qaoo
st rofil ft1(Y1 0r.o ot,t NNO)9 c'i<J\
xa
@@\\oo
6ln(osfNH
r{ O)(\ (t)(Y) Or9 F.'{t
olNol (Nlnrnsi (nN(\tnsl
f\ Flo)o00 0)fnFl
ft1 fr1No)(notJ1
x xxx
6 Fi(Ostd'! qqqo ooo
(\@N@OOr@stt\ ft1 f\ Fl(o lJ1 (o <fdmrn(of\ d {/} {/arYi 13--
}R X:RX
6 6@@\ \\\o ooo
t\ F{ ft1 anN lnFSIfi.)rn6m
NI/)N6F N(oNr.o Fl {/l {./|Fa 9--1r>
t\ slNoFl<fNsfOO Lt') F{ OFi lnNFlFlt.osf€rl (n (O Ol
00d@olf\ (\ "u} r,/,ot {t{/}
x}qsNXXXAIeXXXXXXXFi rn O ft1 rJ1 N cO (O sl 6 ln F\ Or ln 6l Ofrl fr'! q r! ..{ n q n .1 n U.1 4 d'! rr| q'4oooooooooooooooo
ft1 (n o o) ln N ln 01 r\ (n or N N Sf oo o(o sl{/}sl (o N N ln Fl o) t\ N ol c{ rn F{Osf TnNNNO@NtoNlnm@0O-i i Fa oi F.' ri .i i i d oi cxi r'i Fat3(\ {4 {J} (t1 (n fi1 1/} i/} {/} r! {/} Fi {.r} {/}
-vlo) -(o-!n--j -99 9 9<l>
)R )Q -" X X X ;R X ;R :R A A X X :R X
co@o6666000@60(,@@@@\\q\\\\\\\\\\\\\oooooooooooooooo
o lJ) 0 tn d d <f d @ sf fi1 0 (o o) $ rnsf (o{'/lN N (O + Fi O Ln O) O F{ N N NN N r-r Or O O! N O) N st OO (O O) r{ (nd rr .i r.. d F.: F.' + d oo' oi oi F.' 'ri rrio) l!1 sf o N st N (o f\ N d (o sl I\ (oA { (\ O) Fl O N N rn (o (o (O O) lr} Fl!i. {/} Fi ri ffi oo'{/} j {4 + Fi. 'yi {./.} ,yi {/}l/l {/} !{ ^,1 c! <r> r'{ {./} m <rt$ {.4 6l {.r} Fl Fl<rr {/} <fi {>
sf N O rt1 O) O) N m O Fl d) N d N 10 oOFr(\ osloro o sir{r{o)NstooroNd(om6sf
Or !.lF\(n f\Ftd?'l Nm F{sl
t9o.rbdPc9E395
>E6-!o -o^bC UE9t\z6uL.-oo-<i=
m N o F{ sl o (n (n € to 0 st N Fi N NN m {.r} Or l.o d rrl @ N O si d Or sl (o OOor t u'') oo fr.) F{ r\ ol o) N r\ Fr t o ^l(O (n f\ \l F{ O Fl O) (\l O) l\ O) N OO Fl$ {.4 F{ N lJ1 N {/} {.r} {.D Ol Fi st {/} N {.r}tn- vlF{f\ -oO{4O-{/}-rri -Ylj13 t2-j0 <t} lrt
E+rOn,99?56O EEBll 6.E<Eb Evl
(u
(! 0,,cof
--C(J e 0.,EA
=E(J
Fl f\ c) H r\ (O N (O d (O Fl sl c) tO @ t\N O F{ OO a{ N S l.o sl (n Fl tO (\ Fl Olo ln c! o o) lJ1 sf o (o d @o (o or @rc) Fl m a! 6l r! @ sl 6 N d (o @ lrt stN rn ao sl cO rn oO (.o f\ N Ot O) fo { mOr O f\ t\ l'\ t\ r.o fO N ri (\ oO (O st @rn ln r..1 o) d rn (Y) (o (o sf N rn Fr r\ (\N NanOOf\ Ormdc{61OIF{r{sfFt@
sianNFl
bI!
(uElrJ ^EGco (t)>NZ
(o-
E
oz
s! E3 E'T E<=rzt)
=90,bdlouJuor=396
or (o(o ooNlnao rr!oroOr Fl(]Or
<rr o
Fl{/}
6!-!,o(J
ottiiEolE€F{P6,htr^F{U9Tb EH: E!-<co
'l-rz,P#flSoU
co
oG,
(Jo-
co(\droNr\r.o(o01 @oro@ ooroolsfOslFlood@to(n <f@sfO t\o)NO$dN
01Fl
oNo'r
mo
dFlFl
dGl<f'J)NEShSHESXgSS (Do)Oa\| nl (n9=.iou;e. .rl 1
L(Eo
oF'oo
(oUo
oL(DHoN
Flm
(1'
t)do
N
?.{
0.,E(ul r
zl!
fiEEEEI EEcl (J o,Ll e.El .sool o!iE
*l =-E -H E'El SaxE E
-"1 =
g E P P
'tr(!F
ELo:=
l
E
oF
NFl
to-o- - 'i 6
--E - € e'E t '9,EI EiA gEE EFEgU=El I6t 3iF H.EEa>Hl =P,E,:::.q'If:e PXl Cll !uF.9.9.9.9.:q2clq.t.gE 'P
El El g;SgrrEeE;;;6P =r"E
EI EEEEEEHHEEEEifiEEEl EEEEg**gEfff aEr#El p s p p # l*E"t-E $$$"ES g E
oOOlOFlNmddNAINN
Attachment B
Case No. IPC-E-I5-14
Staff Comments
oslt5lt5
Fi ^r ca sf u) (o N oo cD 3 = S 3 : 5 S9o.iz
F{ r-i d
F, (o sf ,n r. E B h p E E 5 x 3 s $tDOIONNGl
zzz
d "-{ N i }"rni.* c
Case No. IPC-E-15-14
Staff Comments
05ll5l15
(o
@|n
|no
"{o)r{o
Fl{/}
NNlJt
01N<f
r-{oo)fnFl
01(ON(no)oro
(/}
O)01r/)
NrJ)
No100
NNNF{ F{ Fioool,)rn!noooqqqooo{r} {r1 {.rr}
(o lo (o@@aNN(\oooooooooci ci citt <ft C>
oo oo ooor o) orm(\Nr) |,) Inoooqqqooo!> {f, {ft
NSTI\6!'l si N r+oo- .1nq
F,l ln N FlF-i (o sl 6n rtr (o- oroot\r@olN C{ {/} (./.}o) <r><t>
ooNd(o(\lf\(otoq oo- o- (o-
6@(oO)
oO Fl 6(0cri + oo' +oNo)^tosfdr{di
F{
o fi.) N O) (o Or O) O) C! O N O\ rJ') ft1 0 0O (t1 F{ N Fl I\ I N ln rrl O Fl m N O) (Orn m O (n Fl sl l,) lJ1 sl u1 (O I.D sf (n O) q1sl sf rn sl $ sf sl \l fn sf si sl sl sl rn <looooooooooooooooqgqcqqqqeqeqqqqqoooooooooooooooo!\ <ft <r> <rt lrt <Jt <i <r> <J> lfi <d lrt <-f, <rt <r> <f>
(o ro ro (o (o (o ro (o (o (o ro to ro (o (o ro@ 6 00 00 6 00 @ oo oo oo oo 6 00 @ 6 @N N N (\ N (\I N ^I 6I N (\ N N (\I N Nooooooooooooooooooooooooooooooooqqqqqqqqqqqqqqqqoooooooooooooooo<.r> {t <4 lf> !} 1f> !) <f> {> 1r} V> <r} {.r} {.r} {/} {/}
rY1 Ot 6 sl f\ <t m sf O m O sf oO Ot N c!.i r- ;< oo Or ro (o oO (o (O Fi o) N (r1 N rnr\ (o ;5 (o 00 rn < sl !n $ sl m l,) (o 0 sfooxooooodoooooHooo-oooooooooooooqq6qqeqqqqqqqqqeoodooooooooooooo1^ L4 {-^ lt} 1r> Ll} |f> <r} 1J} 1/} ar} <f> <r> 1f> <t> 1,1}
o€@@@@€€@00@€60€6ol o o1 0r ol or ol o1 01 0l o) ol o o) g) o)N(\T!Nt\INNNNNNNN6INNl/) ln ln ln ln rn !n ln !n rn u1 ln u) ln u) g)ooooooooooooooooooooooooooooooooci ci ci ci d ct c, ct ci d ci ci d d c, c;1r' <r> *r> <r> 1t> <u> <r> V\ 1r> <r> <.r> <r> <r> *i 1rt <r>
333KIE$5sef,38qeapr.- N d or o or N H N..r-oo.E e S lid il .i Fi d ..: Fa al d oo' oi : :l :'-'-l5s {eIBtliEil.eg$ilsj v, ci ri rri od'{.r! .i {^ + j :^. ti -l Ji$ *3NS d-'=8S.*3-aaalrr$
Fl r\ O Fi N (O N rO Fl (O Fl st O (O 0O ]\NO Fl 6(\Nsf (osi(nFl(DNF{Oro |n N O Or ln sl O (.o Fi 6 0 (D O) OO
r.o Ft m N (\ N oo sf 6 f{ Ft (o 00 ln r+N rA m sf @ !n oo (o r\ r\ o) o m + mo) O t\ N F\ N (O (n N (n N 0O (o <f oO
L rJ1 |. O) r-l lJ) (n (o t.o $ N ln.{ N NNNmoOF\OlmFlFlNo)FiN<Fi@
sf N O ft1 Or O) N m O Fl (n N F{ N (O oOFlNOslg)OOsfFlFlO)N+6(ON!'{(oantf)<foi inlrvi Fi j .iF{NaAFlsf
sn=
O)Lg E8.o {/}€e(,iE
d,
af,
or=T5ir '& -Y
;8.o
boC
#EcJ gb
EO-!<nod.
3ecLo
-d.q-e b=.tJ't: L6(u.LOF
oq(!q'co5e O zo€ctS gA€fir ,i-tr E'r'9nTE6IJEeg ilHi, Pd,y., l!^Eg.E o EEt^ El-
ELoz
socr9b-PUEo-_o6-9E;<==zo
rl1 mNO'lmoln
ot\ot
molft
9-c.i69;G.V)1
o-EI s*e EsE IFrn-El EUE tiT_H.EsE6 e e a
el g s:EE;;;;gsssE: Ee E i'-l dl>!?>>sr Et &EE"Et;tt;tttg.E*:E El E p
EI E;EEg.H .P.H gifiiEmPEE :I ,E E i
El pepp=gggx$s$$E#EE slsEsP E
Ic)N
Fl Fl9oizFi N (n sr u') (o F- € sr 3 = S P : 5
Attachment D
Case No. IPC-E-15-14
Staff Comments
05lr5ll5
S:sos)aqN-
o(,c? oqo66N
otoN.o@- F-FONO.-: 6-oro$ooo
e
ONott@rt{6(D-tO
6
FN@@;olOF
@NNONIN{NOotONto
6
ONONo- lo-toNNotNdoo6 0r_
oo tso-ooro
o
s sss
O NNNo t@oci oi ni si
o N(ooO OFFd ;Eioio o*s
NO-OO \t@Oo- o_'i N-N @@ON @NNN- O_ O- O-
O tf OrO Ne-o-oo
@
N OO@o ooo
- OoOof @oirto o(oo$ @NN
o
oo@N@ e{o; dotci@ose
$ aooN OFoooots !-oo-o@NOF
- F@O; oo--@ NaFo-oG
o
@ NF(ON N(O@o- 6- o- @-@ @@o3 o$F@eO@o +o+O NONo_ t-No
O FrrNo_ooo
(oooNNO
$o@N@_No\ro@r..oop=:p
Eo)E o= gl ss sss..sssss
H E',; g st5 seail ass'ss'^si!Pol oooo-;NrooF*vg(rl
co
"51 8;eBEslsBs{e
=El tsB;sSsHepBEu
oOOTIOFOtN(OOOON(rOF.n@NF-@hOo@ bo@o(ooo@oEdal +o ijNo@rj+@$@y=fl @NNoN@oNo@NXfitrl N$roNN@No@FE=gl |i.4 6id@.j@_jad@OSltul@6FO@N$@iEdl 3 eN 66
o@oNt@oootoNoN@@o9@to@n@@NFOOVON@N9Ocnol $oo@$NNN6o
!q tr= trl Ne @oo (oo-6*6 9l oi --o .i-F5;-Ql I I e9E'9 EI
"=l B$=ENn€sbsfrR
=El BB;SNSHBREIB
trO@$NOoNO(ONOo6@OON(ONOFOFo {6O6O@rF-O
- q ois o$dod@NdoCn ll NN $NFNONO.ONg g El 3-3 x-:-: i 3-I:-3-E.'iCO 6rl o g rNoNSoo9 nl t 6N rF6 @ q@
TNOFNOFTO(OOt'-NO r@!t.OO(ONrOo6NOOO@O@O@B 4 ciJ oairt{ddodrt{x >:-l ts o o q N @ s o o t o
= irf, o-o_ N_qN-o_o-@_@-t-@-,P AiSl 6o ooo@No-Nc{EE>I NNO@OFFNbuJ?l o- FN- N-@-2 !t o N-
{Nomoto@FF@@FC{ O$O O*FFOr5l N_ t_6_o_ F@_o_o_$Oe6l OFNONFTgEEl E 'o r
9Ebla2?;,tz=tol
o
co
E.ENE.rJO6 k=cEEoON!iEE- g! O
E ts=*H.oF-oE=c^'E:SE89?gEoEEETE9# 3i e
E8EE6
oc g
3o
{<$g>r60cBQ
fFE-,=..fi H s n#-r
E| EEEEEcif,-ETE= H a,E E
Fos6r....PPN35$Oi6t9tEU)zt
E:r
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS l5th DAY OF MAY 2015,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-E-15-I4, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
THE FOLLOWING:
LISA D NORDSTROM
REGULATORY DOCKETS
IDAHO POWER COMPANY
PO BOX 70
BOrSE rD 83707-0070
E-mail : [e-mail]
dockets @idahopower. com
TIMOTHY E TATUM
GREGORY W SAID
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-mail : [e-mail]
[e-mail]
CERTIFICATE OF SERVICE