20140516Comments.pdf

KARL T. KLETN
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 THE APPLICATION OF )
IDAHO POWER COMPANY FOR )
AUTHORITY TO IMPLEMENT POWER )
COST ADJUSTMENT (PCA) RATES FOR
ELECTRIC SERVICE FROM JUNE I,2OI4
THROUGH MAY 31, 2015, AND TO UPDATE
BASE RATES IN COMPLIANCE WITH
oRDER NO. 33000.
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
RECEIVIN
?0lrtllAY 16 Ptl 2'02
urrrfrffi{Pie'l}fi !E$ror{
CASE NO. IPC-E.14.05
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission comments as follows on Idaho Power
Company's proposed rate adjustments.
SUMMARY OF APPLICATION
On April l5,20l4,Idaho Power Company ("Idaho Power," or the "Company") filed its
annual Power Cost Adjustment ("PCA") Application. The Application proposes to implement a
base rate increase as required by Commission Order No. 33000. This change also involves a
change to Schedule 89 (Unit Avoided Energy Cost of Cogeneration and Small Power
Production), a PCA rate decrease with revenue sharing similar to last year's application, and a
rate mitigation measure that would apply unused demand-side management ("DSM") Rider
revenues to reduce the proposed increase. According to the Company's Application Idaho
customers will collectively pay about $ 1 1 . I million (or | .04%) more for electricity in the
upcoming year than they do now. Table 1 shows a breakdown of the Company's request.
STAFF COMMENTS MAY t6,2014
Table 1: Idaho Power Proposed
Description
Base Revenue Change
Associated DSM Rider Change
PCA without Revenue Sharing
Revenue Sharing
Mitigation - DSM Rider
Revenue
Revenue Changes
Current
($)
898,955,741
0
166,855,392
(7,276,203)
for Idaho Customers
Proposed
($)
Difference
($)
998,206,633 99,250,892
(3,970,276) (3,970,276)
99,047,509 (67,807,883)(7,602,043) (325,840)
(16,029,724) (16,029,124)
Difference
Total Billed Revenue
Increase in Billed Revenue
1,067,597,568 1,078,714,736
As can be seen in the table, all proposed changes are decreases except the base rate change. The
proposed base rate increase and PCA decrease (including the Company's revenue sharing and
mitigation proposals) are further described below. The Company asks that its proposed rate
changes be effective June 1,2014.
A. Proposed Base Rute Increase
Commission Order No. 33000 in Case No. IPC-E- 13-20 allows Idaho Power Company to
add $99.3 million of normal Net Power Supply Expense ("NPSE") to base rates. The order also
identifies about $4.0 million in increased DSM Rider revenues associated with the base rate
increase. The DSM Rider recovers 4o/o of base revenues. The order further requires Idaho
Power to spread both amounts in the way the PCA spreads cost or revenue amounts, on an equal
p/kWh basis. In addition, the costs are to be assigned to the energy rate components of all rate
schedules. The order specifies that the rate change would be effective June I ,2014 along with
the Company's PCA rates.
Besides increasing base rates, the base NPSE change noted above also requires the
Company to change its rates in Schedule 89, Unit Avoided Energy Cost of Cogeneration and
Small Power Production. See Order No. 32758. Schedule 89 establishes the rate that Idaho
Power pays the owners of some Qualifying Facilities who sell both energy and capacity to Idaho
11,ll7 ,169
I 1,1 17,168
1.04%
STAFF COMMENTS MAY 16,2014
Power. The rate is based on variable costs of generating power at the Valmy power plant. The
current rate is 3.462(lkwh and the proposed rate is 4.133 p/kwh.
B, Proposed PCA Decrease
This year the Schedule 55 PCA rate for each class combines the three traditional PCA
components (forecast, "true-up," and reconciliation) with two additional components (revenue
sharing and rate mitigation). These five components are discussed below.
1. Traditional PCA Components
The traditional annual PCA mechanism has three components: a) a ooforecast" 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 previous 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.
a. Forecast. Forecasted power supply costs for the coming year are based on inputs to the
Company's March 27,2014 Operating Plan. According to the Company, the Idaho
ratepayer's share of the difference between forecasted and base power supply cost is
about $21.7 million. The power supply cost difference is converted to a cents-per-
kilowatt hour (p/kWh) rate by dividing the power costs by projected energy sales. Idaho
Power calculates this rate to be 0.1609 d/kwh.
True-Up. The true-up amount is the difference between forecast and base power supply
costs and revenues from the forecast rate that accrued during the previous year. The
previous year's PCA amount is not precisely recovered because the forecast of expected
costs is never 100% accurate. The true-up amount is also converted to a plkWh rate by
dividing by projected energy sales. Idaho Power calculates the Idaho ratepayer's share of
the true-up amount to be $58.1 million, which is expected to be recovered by applying a
true-up rate of 0.4284 //kwh.
Reconciliation of the True-Up. The reconciliation of the true-up tracks the recovery of
the previous 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
b.
STAFF COMMENTS MAY 16,2014
carried into the following year's true-up reconciliation along with the true-up difference.
Idaho Power calculates the Idaho ratepayer's share of the reconciliation of the true-up
amount and rate to be $19.1 million and0.l4l2llkWh, respectively.
These three traditional PCA rate components combine for a201412015 PCA rate
surcharge of 0.7305 d/kwh (0.1609 + 0.4284 + 0.1412). The implementation of this rate is
expected to recover traditional PCA costs in one year. The proposed rate is 0.5001 p/kWh less
than current PCA rates.
2. Additional PCA Components
Besides the three traditional components discussed above, this year's PCA includes the
revenue sharing and mitigation components discussed below.
a. Revenue Sharing
The Company applies a revenue sharing component to this year's PCA. The Company
calculates $24.1 million of revenue to be shared with customers. The offset to the PCA is $7.6
million and the remaining $16.5 million is to be applied to the pension balancing account.
b. Mitigation Proposal
The Company also applies a mitigation component to this year's PCA. In summary,
Idaho Power proposes to offset the overall June 1, 2014 rncrease by crediting an additional $16.0
million of DSM Rider revenues to this year's PCA. The $16.0 million amount would come from
unused DSM Rider revenues. The Company proposes to spread this amount to the Company's
rate schedules on a uniform percent ofbase revenue basis, and to assign it to the energy rates in
each schedule. These class specific energy credits result in a different combined PCdRevenue
Sharing/mitigation energy rate for each rate schedule.
C. Company's Rate Calculation
Company Exhibit No. 6 shows how the Company developed its proposed Schedule 55
rates. Schedule 55 rates include all of the rate changes proposed in this filing except for the base
rate change and the Schedule 89 rate change. Column I shows the Schedule 55 energy rates
proposed by the Company.
STAFF COMMENTS MAY t6,2014
STAFF AUDIT AND ANALYSIS
Staffls analysis of the Company's proposed base rates and PCA rates is summarized
below.
A. Analysis of Base Rates
Staff checked the Company's calculations of the proposed base rate, 0.7320 p/kWh, and
believes the Company's proposed changes are consistent with Commission Order No. 33000.
This rate change would require changes to almost all of the Company's tariff schedules.
Staff has also reviewed the proposed rate and rate calculations for Schedule 89 (Unit
Avoided Energy Cost of Cogeneration and Small Power Production) and recommends
Commission approval.
B. Analysis of PCA Rates
Staff analyzedthe traditional PCA components (forecast, true-up, and reconciliation) and
additional components applied in this case (revenue sharing and mitigation). Staff s analysis is
as follows.
1. Traditional PCA Components
a. Forecast
The Company's forecast is based on its March 27,2014 Operating Plan. The Operating
Plan reflects the most current information available to the Company when its filing is prepared.
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 Policy Act of 1978 (PURPA). Throughout the year, the Risk Management
Committee ("RMC"), which consists of key Idaho Power employees, reviews and updates the
Company's risk management strategy. An account-by-account breakdown of the Company's
power supply expense forecast is shown on Attachment A to these comments. The chart 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 differences in PURPA Contract Expenses are not shared between the Company and its
STAFF COMMENTS MAY t6,2014
customers. The entire difference in PURPA Qualifying Facility (QF) contracts is passed on to
customers.I
Attachment B shows Staff s calculation of the PCA rate components. Lines I through 18
show the calculation of the forecast rate. The forecast rate is the sum of three rate elements.
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
0.1 807 p/kwh. This rate element captures the effects of expected water conditions, thermal plant
fuel costs and expected market prices which affect power purchases and sales, etc. Although
precipitation amounts are near normal, expected runoff into the Hells Canyon Complex are
below normal because upstream reservoirs are expected to store more than normal amounts to fill
last year's above-normal draw downs.
The second element of the forecast rate component is shown in lines 10 through 12. The
second element includes all amounts, except Demand Response Incentive amounts, which are
passed through to customers without sharing. These amounts are almost entirely PURPA QF
contract costs. This second rate element is 0.0020 P/kWh as shown on line 12. This very small
change from base reflects the fact that this filing includes a current updated base NPSE discussed
earlier in these comments.
The third element of the forecast rate component allows Idaho Power 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 0.0218 p/kwh. The amount is negative because the forecasted
amount is less than the amount included in base rates.
Staff verified that the Company appropriately used the Commission-approved Demand
Response settlement2 to estimate the total expenses to be included in the PCA. The Company's
forecast for Demand Response incentive payments is higher in2014-2015 than in20l3-2014,
primarily due to the reinstatement of the programs for the 2014 season. The Company's forecast
consists of estimated fixed payments for enrolled participants as of April 7. Staff agrees with the
' e Qp is a generating facility that qualifies for QF status under PURPA and l8 CFR Part 292 andhas obtained
certification of its QF status.2 See Case No. IPC-E-13-14.
STAFF COMMENTS MAY t6,2074
Company's approach for forecasting Demand Response payments for 2014, and notes that as a
result of the settlement, the forecasted expenses remain below the base level included in rates.
The above three elements combine to produce the PCA forecast rate component of
0.1609 p/kwh shown on line 18. The forecast rate component is not large this year like it was
last year mainly because base NPSE has been updated to current normalized levels. Staff points
out that any over or under-collected amounts due to forecast effor are trued-up in the following
year's PCA.
b. True-up
Staff has concerns about the Company's true-up calculations. As a result, Staff proposes
a change to the balancing account going forward but no change to the true-up rates to be put in
place on June I ,2014. Staff s concerns are discussed in detail at the end of this section. Before
that, Staff discusses the true-up calculations and the way they have been done in recent cases.
i. True-up Calculations ond Recent History
The Company's f,rling 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 defenal 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. 5 calculates a true-up deferral amount
of $58.1 million. Attachment C contains Staff s verification of the Company's true-up deferral
calculations.
To verify revenues and costs associated with Idaho Power's true-up deferrals, Staff
audited the actual revenues and expenses that occurred during the PCA year (April 1,2013
through March 3O,2Ol4). 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. 5 are correct,
STAFF COMMENTS MAY 16,2014
and that the megawatt hours used for the Actual Firm Load, as shown on page 1, line l0 of
Company Exhibit No. 5 are correct.
The large true-up balance, $58.1 million, indicates that the prior year's forecast was
inaccurate. The actual hydro generation was lower during the PCA year when compared to what
was built into the forecast. This lower hydro generation also contributed to lower surplus energy
sales revenue. These two factors are the most signif,rcant factors that contributed to the large
PCA true-up deferral balance.
The PCA true-up component includes the following items:
. Load Change Adjustment. This year's true-up calculation includes a negative load
change adjustment of $643,172. Actual loads during the true-up year were below normal
loads in 6 months and above normal in 6 months. Overall, the actual load for the PCA
year was above normal by 36,461MWh. This represents a 0.23% overall increase in
load. During the PCA year, the monthly increase in loads was greater than the monthly
decrease in loads, producing a negative Load Change Adjustment amount.
The load change adjustment is the product of the positive or negative load growth
and the load change adjustment rate (LCAR) of $17.64lMWh for the months of April
2013 through March 2014. The LCAR is composed 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 a portion of lost fixed production costs.
The result is that $643,172 (beforejurisdictional allocation and PCA sharing) has
been subtracted from the deferral balance for recovery from customers in this year's PCA,
This LCAR-related decrease is a benefit to customers and is subject to jurisdictional
allocation and sharing.
o Water Leases. The Company sometimes leases water from several entities for hydro
power production. 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 $706,411. The amount included in base
rates is $1,828,640. The difference of $1,122,229 is included in the deferral balance.
This decrease in water lease expenses from base expenses is a benefit to customers and is
subject to jurisdictional allocation and sharing.
STAFF COMMENTS MAY 16,2074
Fuel Expense - Coal. Some of Idaho Power's electricity comes from coal plants. Idaho
Power 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. For the April 2013 to March 2014 PCA period, the
total coal expense for the three plants is $160,995,670. The total coal expense included
in base rates is $167,192,743. This year's PCA defenal balance includes a difference
between costs currently included in rates and actual costs of $6 ,197 ,073. This decrease in
coal costs from base costs is a benefit to customers and is subject to jurisdictional
allocation and sharing.
Fuel Expense - Gas. Idaho Power owns and operates gas-fired combustion turbine
generating plants at the Evander Andrews Power Complex (3 Danskin units) and Bennett
Mountain in Mountain Home, Idaho; and Langley Gulch, near New Plymouth, Idaho.
Langley Gulch was included in base rates beginning in July 2012. Staff reviewed the
natural gas purchases in conjunction with the Company's Operation Plan. Staff found
that the transactions were reasonable and followed the Risk Management Committee
recommendations.
For the April 2013 through March 2014PCA period, the total variable gas and
gas transportation expense for all the gas plants was $59,228,806. The total gas and gas
transportation expense included in base rates is $51,934,201 . This increase in gas
expense from base rates is included in the PCA. This year's PCA defenal balance
includes a difference between costs currently included in rates and actual costs of
$7,294,605. 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 power purchases and sales in conjunction
with the Company's Operating Plan. Staff believes the transactions were reasonable and
that they followed the Risk Management Committee recommendations. These
transactions were made with an assortment of creditworthy partners on a timely basis,
and there were no transactions conducted with an Idaho Power affiliate.
a. Power Sales. During the PCA year ending March 31,2014, the Company sold
off-system surplus power totaling $66,784,731. The total surplus sales included
in base rates is $124,916,153. This decrease in the power sales from base rates is
included in the PCA. Actual surplus sales were less than base amounts by
STAFF COMMENTS MAY 16,2014
$58,131,422. This decrease in revenues is a cost to customers and is subject to
jurisdictional allocation and sharing.
Company witness Tatum explains that forecasted surplus sales deviated
from actual surplus sales because surplus sales were impacted primarily by lower
hydro generation. See Tatum Di, Exhibit No. 2, p. 1 at 3. Tatum also explains
that surplus sales were lower due to lower production at Langley Gulch power
plant, with the accompanying decrease in natural gas costs. In addition, there
were months where surplus sales were lower due to maintenance at Langley
Gulch and lower than expected natural gas prices, but that overall the decrease in
surplus sales directly correlates to the lower than anticipated hydro generation.
b. Power Purchases. During the PCA year ending March 31,2014, the Company
made $78,523,687 in market power purchases, excluding its PURPA contracts.
The amount of power purchases included in base rates is $45,510,094. Actual
power purchases were more than base amounts by $33,013,593. This increase in
purchases is a cost to customers and is subject to jurisdictional allocation and
sharing.
Third-Party Transmission. In Order No. 30715, the Commission found that third-party
transmission costs that are incurred in conjunction with market purchases and off-system
sales should be tracked 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 April2013 through
March 2014 PCA period, the actual third-party transmission expense is $5,760,718. The
third-party transmission expense included in base rates is $8,262,000. This year's PCA
deferral balance includes the difference between actual costs and base costs of
$2,501 ,282. Because the actual costs are less than the amount included in base rates, this
amount represents a benefit to customers. This benefit to customers is subject to
jurisdictional allocation and sharing.
Hoku First Block Energy. In Order No.32426 (Case No. IPC-E-I1-08), the Commission
determined that the first block energy revenue from Hoku is to be included in base rates
like secondary sales revenue. The variation between what is built into base rates and the
actual Hoku revenues is tracked in the PCA. The amount of Hoku First Block Energy
revenues included in base rates is $23,921,467. The actual amount of Hoku First Block
STAFF COMMENTS 10 MAY 16,2014
Energy revenues during the current PCA period is $0. New base rates set in Order No.
33000, Case No. IPC-E- l3-20, no longer includes any Hoku revenues. The actual
revenues during the PCA year are less than the amount included in base rates by
$23,921,467. This decrease in revenues is a cost to customers and is subject to
jurisdictional allocation and sharing.
Emission Allowance Sales. In Order No.32424, the Commission required 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, emission allowance
sales totaling $24,000 are included in the deferral balance. This increase in revenues is a
benefit to customers and is subject to jurisdictional allocation and sharing.
Renewable Enerey Credit Sales. In Order No. 30818, the Commission ordered that
revenues from the sale of renewable energy credits ("RECs") benefit customers and be
subject to jurisdictional allocation and sharing. The amount included in the deferral
balance is $1,874,892. This increase in revenues is a benefit to customers and is subject
to jurisdictional allocation and sharing.
Actual PURPA Purchases Including Net Metering and Raft River Expenses. For the
April2013 through March 2014Pc{period, the actual PURPA expense is
$133,003,093. The PURPA expense included in base rates is $62,851,454. 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
$70,15 1,639. 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-I l-08, the
Commission required that Demand Response lncentive Payments be included in base
rates and that differences between base and actual expenses be tracked through the PCA.
Idaho Demand Response Incentive Payments are directly assigned to Idaho and are not
subject to sharing. For the PCA period (April 2013 to March 2014), the actual Demand
Response Incentive Payments are$4,197,214. The base amount of Incentive Payments
included in base rates during the PCA period is $11,252,266. The difference between the
l1STAFF COMMENTS MAY 16,20t4
actual amount and the base amount is $7,055,052 and is a reduction to customer PCA
costs. The Demand Response Incentive Payments are not currently subject to sharing and
are allocated 100% to the Idaho jurisdiction.
Table 2 summarizes the composition of the deferral balance.
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
(643,172)
(1,122,229)
(6,197,073)
7,294,605
58,131,422
33,013,593
(2,501,282)
23,921,467
Subtotal
Emission Allowance Sales Credits
Renewable Energy Credit (REC) Sales
111,897,331
(24,000)
(1,874,892)
Subtotal
Amount After Jurisdictional Allocation and Sharing
Qualiffing Facilities - After Jurisdictional Allocation
109,998,439
99,273,591
66,644,057
Demand Response Incentive Payments (7,055,052)
Total Expense Items
Revenue from PCA Forecast
Deferral Balance
Interest on the Deferral Balance
158,862,596
266.054
701,039,775
57,822,821
Total Deferral 58,088,875
The Company proposes a 0.4284 p/kwh true-up rate. Staff calculates the same rate as
the Company, as shown on Staff Attachment B,line 23.
t2STAFF COMMENTS MAY 16,2014
ii. Staff's Concerns about the True-up
The purpose of the PCA is to track the difference between actual power supply expenses
and power supply expenses collected through base rates and then true-up to "ensure the amount
recovered is no more or less than actual power cost paid by the Company."3 The recovery of
actual NPSE can be mathematically expressed as follows:
Actual NPSE _
Cost
PCA
(Base-to-Actual True-up Deferral)
Total Recovery of Actual NPSE
Recovery of NPSE
through Base Rate Sales
The problem with the Company's true-up calculation is that it uses load-at-generation in
the Load Change Adjustment (LCA) rather than Idaho jurisdictional sales. Taking the difference
between actual load-at-generation and load-at-generation used to establish base rates introduces a
line loss bias. Line loss is the difference between load-at-generation and load-at-sales. In this
case, actual line losses are significantly less than those assumed in the last rate case resulting in
underestimated actual sales used to determine NPSE actually collected. See Attachment D to
these comments
Because of base-to-actual line loss differences and because the Company uses loads at
generation, Staff believes that the Company has failed to properly include power supply expense
revenue actually collected from customers through base rates and has therefore over estimated
the amount of additional expense that needs to be collected through the PCA true-up component.
The adjustment for actual NPSE revenue collected from customers includes four parts: l) Actual
non-PURPA NPSE; 2) energy classified fixed production costs; 3) Qualifying Facility Net Power
Supply Expense (QF NPSE); and 4) DSM incentive costs. In summary:
1) During this PCA period, actual non-PURPA NPSE was $226.5 million for the Idaho
jurisdiction before sharing. The amount of non-PURPA NPSE collected through actual sales
for the period totaled about 5125.7 million (13.85 million MWh in actual Idaho sales, times
3 See Order No. 30828, Case IPC-E-O9-l l. The Commission States, "We remind customers frustrated by the rate
increase that the PCA does not influence Idaho Power's profits. The Company's normal power costs are recovered
in its base rates, and the PCA recovers only the actual variable costs the Company pays to supply the power used by
its customers. Both the true-up component and the reconciliation of the tn"re-up [tme-up of the true-up] are measures
in the PCA to ensure the amount recovered is no more or less than the actual power costs paid by the Company."
l3STAFF COMMENTS MAY 16,2014
$9.079/MWh of non-PURPA NPSE in base rates) for an uffecovered balance of $100.8
million. The Company has requested a true-up in this case of $106.6 million (the Company
has included a non-PURPA NPSE LCA of -$ 279,540) resulting in a $5.9 million over
collection of actual non-PURPA NPSE before sharing and $5.6 million after sharing.
2) Idaho's share of actual energy classified fixed production cost is about $109.1 million. This
amount is assumed to be the same amount included in base rates through the authorized
LCAR. Total recovery of $ I 14.4 million consists of collection through base rates of $ 1 14.7
million (13.85 million MWh in actual Idaho sales times $8.28llMwh of cost embedded in
base rates) plus a reduction of about $250,000 through the energy classified fixed production
cost portion of the Company's LCA. Total over-collection during the deferral period would
be about $5.3 million before sharing and $5.1 million after sharing.
3) Idaho's share of actual QF NPSE during the deferral period was $126.4 million. The amount
of QF NPSE collected through actual sales for the period totaled about $62.8 million (13.85
million MWh in actual Idaho sales, times $4.53/MWh of QF NPSE in base rates) for an
unrecovered balance of $63.6 million. The Company proposes to collect a true-up of $66.6
million resulting in an over collection of about $3.0 milliorr.a No additional sharing is
applied to this component.
4) Idaho's share of actual DSM incentive costs during the defenal period was $4.2 million.
The amount of DSM incentive costs collected through actual sales for the deferral period
totaled about $11.8 million (13.85 million MWh in actual Idaho sales, times $0.85/MWh of
DSM incentive costs in base rates) for an over recovery of $7.6 million. The Company
proposes to refund $7.1 million resulting in a continued over collection of about $500,000.
See Attachments E and F to these Comments for further detail.
When actual revenue collected from customers during the PCA period in these four
NPSE categories are compared to actual NPSE incurred during the PCA period, the true up
amount proposed by the Company in this case is $14.2 million higher than it should be. Staff
maintains that the proposed adjustment represents an improvement in PCA accuracy and not a
change in PCA methodology.
Given the complex nature of the adjustment calculations and the limited time for party
review, Staff recommends that Company-proposed rates be approved beginning June 1,2014.
However, Staff further recommends that the Commission hold its decision on the $14.2 million
adjustment so the parties can hold a workshop to evaluate the adjustment and its justification,
and report back to the Commission. Once the parties have an opportunity to review the
a To comply with Commission Order, Staffapplied 95% sharing to the QF NPSE portion of the LCA.
STAFF COMMENTS t4 MAY 16,2014
adjustment and report back to the Commission, the PCA deferral balance can be adjusted as
necessary and included in next year's PCA.
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 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 from Order No. 32821 and the transfer of the deferral balance from the previous
PCA year, as well as verified the actual monthly collections and interest calculations and finds
them to all be correct.
Table 3: True-Up Reconciliation
2012-13 Forecast True-Up 62,204,982
20ll-12 True-Up of the True-Up Balance (7,719,349)
Revenue Sharing (Order No. 32821 + interest) (7.172.095)
Net Amount Set for Recovery/(Refund) 47,313,538
Collections from True-Up Rates
Interest
(28,593,706)
42r.085
Sub-Total
True-Up Reconciliation
(28,t72,62t)
19,140,917
This is the amount recommended for recovery from customers by the Company and Staff.
Dividing this amount by expected sales produces the true-up reconciliation rate of 0.1412
p/kwh. This calculation is shown on Attachment B, line 25.
Staff calculates the sum of all three of the true-up rate components to be 0.7305 //kWh as
proposed by Idaho Power.
2. Additional PCA Components
a. Revenue Sharing
In 2010, Commission Order No. 30978 established a mechanism that in part required
Idaho Power to share revenue if the Company's actual Idaho jurisdictional year-end Return on
STAFF COMMENTS 15 MAY 16,2014
Equity ("ROE") exceeded 10.5% in the years 2009 through 2011. If revenue sharing was
triggered, the Company was to share 50%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 9.5o/o and 10.5%. Revenue sharing was
triggered for the year ending December 31,2011.
Order No.32424 modified the revenue sharing mechanism and extended it through2}I4.
Order No. 32424 reduced the sharing level to 10%, with equal sharing between customers and
the Company when the ROE is greater than 10% up to and including 10.5%. This customer
portion of the "revenue sharing" benefit is 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 10.5%, the earnings above 105% continue to be shared, with customers receiving
75Yo 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
amounts the Company would otherwise be allowed to collect from customers. Revenue sharing
was triggered for the years ending December 3l , 2012 and 20 I 3.
In this year's filing, the Company calculates $24.1 million, after tax gross-up, of revenue
to be shared with customers. The offset to the PCA is $7.6 million and the remaining $16.5
million is to be applied to the Company's pension balancing account. Idaho Power 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 beginning June 1, 2014. This is the same
methodology used to allocate the revenue sharing in previous years. These proposed adjustments
decrease rates by about 0.76% relative to current base revenues and are shown in Company
Exhibit No. 4.5 For the four special contract customers, the Company proposes they each receive
a flat dollar-per-month credit during the PCA year. The proposed annual credits, as shown in
Exhibit No. 4 are: Micron-$163,742; Simplot-$62,390; DOE-$80,750. These rates are included
in Tariff Schedule 55, which is proposed to be effective June 1,2014 and remain in effect for one
year.
Staff traced every line item of this year's Additional Investment Tax Credit Analysis
Worksheet6 to the monthly financial statements provided by the Company for 2013. The
t Tatum, DI Exhibit No.4
u Tatum, DI Exhibit No. 3
STAFF COMMENTS t6 MAY 16,2074
Additional Investment Tax Credit Analysis Worksheet s for 2012, September 20 I 3 and Year End
2013 were reviewed for comparison purposes. The methodology was consistent across years and
no material differences were noted. Staff also re-calculated the revenue sharing percentages for
the total system as well as the Idaho allocation.
Staff reviewed the PCA class allocated revenue sharing for 2013 and2014. Both years
were calculated using the same methodology, which was consistent with Mr. Tatum's direct
testimony,T and were based on each class's proportional share of the forecasted base revenues.
The percent of revenue change for 2013 was 0.81%, and for 2014 itis 0.760/o.
After reviewing the Company's Additional Investment Tax Credit Analysis Worksheet
and supporting documentation, Staff believes the Company has correctly calculated and allocated
shared revenues.
b. Mitigation
Staff reviewed Idaho Power's proposal to transfer from the energy efficiency tariff Rider
to the PCA: (1) $16.0 million of 2014-2015 current and forecasted surplus funds; and (2)
ongoing, annual $4.0 million from the rider to the PCA to maintain the revenue neutrality of
moving $99.3 million of power supply expenses to base rates.
Staff reviewed the Company's forecasted energy efficiency revenues and expenditures
through May 2015 and agrees that funds collected in excess of the energy efficiency expenses
should be returned to customers. However, Staff believes it is inappropriate to collect money
from customers for the express purpose of funding energy efficiency programs and then use
those funds to offset increased expenses associated with the Company's supply-side resources,
especially prospectively. On that basis, Staff makes two recommendations.
Staff believes that to the extent the Company does not spend the $16.0 million surplus on
cost-effective energy efficiency, it should be refunded to customers as a reduction to the energy
efficiency services portion of their bills rather than through the annual adjustment mechanism.
Funds were collected from customers under the premise that they would be used for energy
efficiency. To use those funds for any other purpose is inconsistent with the terms under which
they were collected. Refunding the funds by reducing energy efficiency services assures
' Tatum, Dl page 20-21
STAFF COMMENTS t7 MAY 76,2014
customers that the funds collected through the Rider remain dedicated to the Company's energy
efficiency efforts.
Staff has also verified the Company's calculation of the $4 million DSM Rider transfer
necessary to maintain the revenue neutrality of the $99.3 million transfer of power supply costs
into base rates for the current PCA year. Staff recommends that $20 million be returned to
customers as a net reduction to the energy efficiency services portion of the bill for the upcoming
PCA year, with the rates per customer class as shown in Column G of Company witness
Wright's Exhibit No. 6. The financial effect on customers' bills is the same under both the
Company and Staff s refund methods, but Staff s recommendation is consistent with how the
energy efficiency funds were collected.
To ensure that future DSM rider surpluses do not occur, Staff recommends that the
Company review the current DSM funding mechanism to determine if a normalized level of
DSM expenses should be moved into base rates and the energy efficiency tariff Rider
discontinued. In that scenario, actual DSM expenses would be tracked through the PCA and
subject to true-up. If Idaho Power spends more or less than is collected in base rates, 100%o of
the difference would be collected through the PCA.
Shifting DSM expenses to base rates with true-up through the PCA assures that unspent
Rider funds do not accrue in the future. Moving DSM expenses into base rates fulfills the
"revenue neutral" requirement from Order No. 33000 without adjusting the DSM Rider balance
annually until the next general rate case.
The change in base revenues with true-up through the PCA, effective June 1, 2014, will
enable the Company to collect about $40 million through the tariff Rider, far surpassing its
recent and projected DSM expenses. The Company's forecasted DSM expenses through May
2015 lead Staff to believe that the DSM balancing accounts will have a surplus indefinitely. With
base expenses set closer to forecasted levels of expenditures- currently around $22 million-
and deviations tracked though the PCA, customer funds will more closely align with the
Company's energy efficiency efforts than they do under the current Rider mechanism.
Therefore, Staff recommends that: l) $20 million in surplus energy efficiency tariff Rider
funds be credited to customers as a reduction to the energy efficiency services portion of bills
coincident with the 2014-2015 PCA; and2) the Company assess whether moving forecasted base
energy efficiency expenses from the tariff Rider to base rates, for annual reconciliation at 1000 ,
serves the interest of customers.
STAFF COMMENTS l8 MAY 16,2014
3. PCA Summary
Staff has included two attachments that provide summary or historical information
concerning the PCA. Staff Attachment G summarizes PCA expense amounts and rate
components for this case. The attachment also shows amounts allocated to other jurisdictions
and amounts shared with shareholders. Attachment H is a bar graph that shows the amount of
each PCA since its inception. Attachment H only includes the amounts associated with the
traditional PCA components of the Forecast, True-Up and Reconciliation of the True-Up.
PCA Review Constraints
The Commission and Staff are afforded 45 days from when the Company files its annual
PCA for review and the issuance of a final order. The expedited processing of the case is
necessary because power supply expenses must be forecasted in early spring and the timing of
rate changes must coincident with the summer season. Because the forecast is primarily driven
by snowpack, it is advantageous to base projected power supply costs on snowpack reports that
reflect the best estimate of runoff, typically around April 1.
The complexity of the PCA continues to evolve, causing a compressed processing
timeline that constrains a more complete evaluation of the filing. As long as the forecast
component remains in place, the timeline will remain condensed. Staff believes some of the
pressure associated with review would be alleviated if the Company filed its workpapers as part
of its Application rather than after Staff or other parties have requested them. Doing so would
benefit Staff and intervening parties by expediting the review process. Staff recommends the
Commission direct the Company to provide all workpapers in functional format as part of its
annual PCA filing.
C, Staffs Rate Calculations
Staffls base rate calculations are shown on Attachment I. Attachment I demonstrates that
an equal l/kWh rate of 0.7320 (,lkWh recovers the NPSE amount of approximately $99.3 million
as ordered in Commission Order No. 33000.
Traditional PCA rates are calculated on Attachment B to these comments. The uniform
0.7305 P/kWh PCA rate surcharge is the sum of the three traditional PCA components (0.1609 +
0.4284 + 0.1412). This new PCA surcharge rate is a substantial decrease from the current rate of
1.2306 (lkwh.
STAFF COMMENTS l9 MAY 16,2014
The revenue sharing rate decrease of approximately $7.6 million is spread to the
individual rate schedules on an equal percentage ofbase revenue basis. The rate spread reduces
the revenue to all schedules by 0.76 %. The reduction is credited through the energy rates of
each schedule. Attachment J shows these calculations. This process creates a different rate for
each schedule as shown in Column F of the attachment. The Staff calculations agree with those
presented by the Company.
As previously discussed, the Company proposes $20.0 million in rate mitigation. The
amount would come from DSM Rider funds that can be broken into two parts. The first part is
about $4.0 million that is expected to accrue to the account each year as a direct result of the base
rate increase approved in Order No. 33000 and implemented as part of this case. The additional
$16.0 million would come from unused tariff Rider funds. The $4.0 million amount is to be
allocated and recovered on an equal P/kWh basis and the $16.0 million amount is to be allocated
on an equal percent of base revenue basis. Attachment K shows these calculations. These are
the same rates proposed by the Company. Staff recommends crediting the $20.0 million back to
customers as a net amount on the Energy Efficiency Services line on each customer's bill.
Attachment L shows all Schedule 55 rates components.
The Company's tariff with the proposed rates is included as Attachment 1 to the
Company's Application.
D, Customer Relations
Customer Notice and Press Release
Idaho Power hled copies of its press release and customer notice with its Application on
April 15,2014. Staff reviewed the press release and determined that it complies with the
Commission's Procedural Rule 125, IDAPA 31.01.01.125. Staff has two primary concerns
regarding the customer notice.
Staff is concerned that many customers will not receive timely notice of the Company's
Application. Rule 125.03 provides that "Distribution of customer notices shall commence when
the utility files its application or as soon as possible thereafter." Document design and the text of
a customer notice are prepared in-house by Idaho Power and are finalized shortly before an
application is filed. After filing, the Company conveys the document to a printing company in
Boise. After printing, notices are shipped to Idaho Power's billing services contractor in
California for inclusion in customer bills. Bills are then mailed to Idaho Power's customers
20STAFF COMMENTS MAY 16,2014
using USPS bulk mail. According to Idaho Power, it normally takes 10 calendar days after an
application is filed to complete the entire process. For this case, Idaho Power expedited the
process, shaving three days from the usual time frame. The customer notice is being mailed with
cyclical billings beginning on April 22and ending May 21. Customers who are billed on the
hnal day of the cycle (May 21) should receive their bills and notices within two business days
(Friday, May 23).
This means that many customers will not receive notice of the case until after the
comment filing deadline of May 16,2014. Other customers who receive notice on or shortly
before the comment deadline will not have a reasonable opportunity to prepare and file timely
comments. To remedy this problem, the Commission can suspend the proposed effective date
and extend the comment period. See $ 61 -622,ldaho Code. However, the fact that other
changes affecting rates, e.g., the FCA and the switch from non-summer to summer rates, are
linked to the same effective date (June 1) make it very difficult for the Commission to do so.
The Commission also has the discretion to accept and consider late-filed comments.
Doing so will mitigate but not entirely resolve the problem created by untimely notification of
customers. The Commission must issue its order in this case by Friday, May 30 in order to meet
the Company's requested effective date. Monday, May 26, is a holiday (Memorial Day), which
decreases the amount of time the Commission has to deliberate and reach a decision. Because
there is no mail delivery on May 26,there is one less day for the Commission to receive
comments mailed by customers. Given the circumstances surrounding the expedited treatment
of this case, Staff 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.
Staff is also concerned that the Company includes information about its fuel mix in its
PCA customer notice. Although Staff supports the Company's efforts to provide resource
information to customers, notices about proposed rate changes are not the appropriate vehicle.
The Commission requires that the information included in customer notices be "clearly
identified, easily understood, and pertain only to the proposed rate change." See Rule 125.03,
Rules of Procedure.
Investor-owned utilities in Idaho, including Idaho Power, voluntarily provide a resource
portfolio report to customers annually. The 2007 ldaho Energy Plan recommended that utilities
provide this information to customers, and the 2012ldaho Energy Plan recognrzed the utilities'
STAFF COMMENTS 2t MAY 16,2014
compliance with this recommendation. See pp.54 &.55,2012ldaho Energy Plan. To comply
with both the Idaho Energy Plan and the Commission's Rule 125.03, Staff recommends that
Idaho Power provide this valuable information through billing inserts, not customer notices
pertaining to proposed rate changes.
Customer Comments
As of May 12,2074, four comments were received from customers regarding the PCA.
All of the comments opposed the proposed increase. One customer mentioned a decrease in
usage after adding insulation and energy-efficient heating and air conditioning; despite that fact,
the bills increased. Another customer questioned the need for a rate increase given the current
water surplus. Customers also addressed the Annual Adjustment Mechanism, tiered rates,
executive compensation, and hardships caused by rising electric bills.
In both its press release and customer notice, Idaho Power describes the impact of its
proposal on rates. Part of the Company's proposal is to use $20 million in energy efficiency
funds to offset increased power supply expenses. This one-time rate mitigation measure is
factored into the calculation of the total impact the Company's proposal has on rates. Both the
total dollar amount and overall percentage increase is provided, as well as a breakdown of the
percentage increase for each major customer class. While the Company's press release and
customer notice both mention the Company's proposal to offset power expenses by using energy
efficiency funds, it does not quantify the overall percentage increase or provide a breakdown by
customer class. As a result, customers are not alerted to the gross rate impact of the Company's
request should the Commission decide not to accept the Company's rate mitigation proposal. To
enable customers to fully understand possible rate impacts, Staff recommends that in future cases
where rate mitigation is proposed, the Company should explain what the impact will be with and
without rate mitigation.
STAFF COMMENTS 22 MAY 16,20t4
STAFF RECOMMENDATIONS
Staff recommends that the Commission approve the base rates proposed by Idaho
Power Company. Staff also recommends that the Commission approve the revenue sharing
amounts proposed by the Company; specifically, PCA revenue sharing of $7,602,043 and a
pension balancing account contribution of $ 16,5 12,853.
Staff recommends that the Commission approve Schedule 55 rates as filed in
Attachment I to the Company's Application. Staff recommends that new base rates and updated
Schedule 55 rates be effective June 1,20).4.
Staff further recommends that the Commission defer any consideration of Staff s
proposed adjustment to the True-up deferral balance of $14,196,038 so the parties can hold a
workshop to evaluate it and then report back to the Commission. The PCA deferral balance can
then be adjusted and included in next year's PCA.
Staff also recommends that: 1) $20 million in surplus energy efficiency tariff rider funds
be credited to customers as a reduction to the energy efficiency services portion of bills
coincident with the 2014-2015 PCA; and2) the Company assess whether moving forecasted base
energy effrciency expenses from the tariffRider to base rates, for annual reconciliation at l00yq
serves the interest of customers.
Staff further recommends that the Commission direct the Company to provide all
workpapers in functional format as part of its future annual PCA filings.
Staff recommends that the Commission accept late-filed comments from customers in
this case.
To comply with both the Idaho Energy Plan and the Commission's Rule 125.03, Staff
recommends that Idaho Power provide resource portfolio information to customers through
billing inserts rather than customer notices pertaining to proposed rate changes.
Staff recommends approval of the change to Schedule 89 rates as proposed by Idaho
Power.
STAFF COMMENTS 23 MAY 16,2014
Respectfully submitted this (t th day of May 2014.
*,a , ru^
Karl T. Klein
Deputy Attorney General
Technical Staff: Stacey Donohue
Keith Hessing
Mike Louis
Kathleen Stockton
Sandra Walker
Nancy Hylton
i:umisc/comments/ipce l4.Skksdkhmlklsswnh comments
STAFF COMMENTS 24 MAY t6,2014
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Attachment A
Case No. IPC-E-14-05
StaffComments
05116114
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2014-2015 PCA - Twenty-Second Annual
tPc-E-14-05
Staff Case
(a)
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
''t 8
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
(c)
Units
($)
($)
($)
(Yo)
($)
(MWH)
(6/kwh)
($)
(MWH)
(6/kwh)
($)
(MWH)
(0/kwh)
(0/kwh)
(d)
Base
Rate
($/MWh)
(b)
Descrigtion
Forecast 2013-2014:
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 Firm Sales
RAte for PURPA
Demand Response lncentives (100%)
ldaho Jurisdictional Sales
Rate for Demand Response
Total Forecast Rate
True-Up of 2013-2014:
True-Up of the True-Up:
PCA Rates:
PCA Rate Adjustment From Base
PCA Rate Currently in Effect
Difference - Last Year to This Year
160,578,735 187,593,267
0
-18iM
133,853,869 134,142,386
11,252,265 8,290,603
(e)
Forecast
(f)
Difference
27,014,532
0.95
25,663,805
14,200,871
0.1807
288,517
't4,200,871
0.0020
(2,961,662)
13,558,865
(0.0218)
(s)
Rate
0.1807
0.0020
(0.0218)
0.1609
(d/kwh)
0.1284
0.1412
I o.?30-tl
1.2306
(0.5001)
(0/kwh)
(s/kwh)
(c/kwh)
($)
58,088,876
19,140,917
(MWh)
13,5s8,865
13.558,865
Energy
(MWh)
13,558,865
13,558,865
($/MWh)
4.284
1.4117
Revenue
($)
21,816,214
58,086,1 78
36
37
38
39
40
41
42
43
Note: Negative rates and amounts indicate benefits to ratepayers.
Expected PCA Revenues:
Forecast Revenue
True Up Revenue
True Up ofTrue Up Revenue
Total
13.558.865 19.145.117
7.305 99,047,509
13,558,865,000 Company Estimate ol 201412015 ldaho Jurisdictional sales
14,200,871,000 Company Estimate ol 201412015 normalized system firm sales
1.609
4.284
1.412
NOTES:
Rates are for a one year recovery period
Rates exclude Revenue Sharing
Attachment B
Case No. IPC-E-14-05
Staff Comments
05/16114
TRUE-UP CALCULATIONS FOR 2013 - 20,I4
FOR
IDAHO POWER COMPANY PCA
cAsE NO. |PC-E-14-05
(Base Cosb are Redistributed)
2013 2013 2013 2013 2013 2013 2013
4 Actual ldaho Jurisd. Sales'MWh 922,125 931,654 350,250 1,506,796 1,586,090 1,370,093 1,002,511
5 For€cast Rate $/MWh 5.099 5.099 8.258 8.258 8.258 8.258 8.258
6 R€venue $ 4,701,915 4,750,504 2,892,365 12,443,121 '13,097,931 11,314,228 8,278,736
7
8 Load Chango Adiustmont
2 DESCRIPTION Units APR MAY JUN JUL AUG SEPT OCT
3
I Actual Systom Firm Load - Adjusted
10 Nomalized Fim Load
MWh 1,076,204 1,328,51 1MWh 1.047.064 't.271.705
1,552,985 1,793,750 1,654,5521,393,674 1,744,091 1,586,231
'1.192.855 1.068,6011,279,154 1,098,456
1 'l Load '11
12 Exp€nse Adjustment
IJ
14 Non.QF PCA
15 ACTUAL:
'16 Water Leases
'17 Fu6l Expense - Coal
'18 Fuel Expsnse - Gas
1 9 Non-Fim Purchases
20 Third Parly Transmission
2'l Surplus Sales
24 Sub-Total
25
26 BASE:
27 Wat€r for Pow€r (Leases)
28 Fuel Expense - Coal
29 Fuel Exp€nse - Gas
30 Non-Firm Purchases
31 Third Party Transmission
32 Hoku First Block Energy
22HokuFirstBlockEn€rgy $ 0 0 0 0 0 0 0
23 Expense Adiustment $ (514,030) (1,002,058) (2,810.246) (875,985) (1,205,182) 1.522,314 526,642
$ (514,030) (1,002,058) (2,810,246)(875,985) (1,205,182) 1,522,314 526,642
$0010't,661571,450000$ 8,027,505 10,281,418 13,890,512 14,894,959 16,158,574 12,711,%3 12,721,007$ 1,486,610 2,699,000 5,400,087 7,146,220 7,870,882 5,974,810 1,454,620$ 3,743,953 4,453,123 5,532,095 14,646,694 10,455,494 5,294,844 5,661,427$ 257,799 357,848 763,792 897,309 796,450 512,842 492,775$ (1,442,293) (1,223,681) (1,450,264) (2,397,724) (2,031,595) (6,426,201) (6,225,007)
$ 11,559,544 15,565,649 21,427,637 34,882,923 32,044,622 19,590,572 14,631,464
$ 123,719 122,164 155,409 195,168 2c6,542 '184,523 132,222$ '11,311,629 11,169,485 14,209,042 17,844,222 18,884,,185 16,870,940 12,089,048$ 3,513,672 3,469,518 4,413,680 5,542,857 5,865,895 5,240,531 3,755,157s 3,079,041 3,040,349 3,867,721 4,857 ,222 5,140,301 4,592,293 3,290,655$ 558,976 551,952 702j54 88'i,790 933,'18'1 833,695 597,393$ (1,618,436) (1,5s8,0s8) (2,032,990) (2,5s3,101) (2,701,896) 12,413,847) (1,729,667)
2,325,139 6,458,776 9,670,054 19,353,611 '16,079,836 6,216,147 4,960,574
33 Surplus Sales S (8,451,355) (8,345,154) ('10,616,124) (13,332,107) (14,109,103) (12,604,931) (9,032,194)34 Sub-Total $ 8 517,246 8,410,2'16 10,698,892 13,436,051 14,219,105 12,703,204 9,102,614
35
36
3TEmissionAllowancBsalescredit $ 0 0 0 0 0 0 (24,000)
41 D€feral (Shared and AllocatBd) $
42
43 Oemand R€spons€ lncentive Pmts.
44 Actual
38
39
40
47 Oeleral
48
49 QF Deferal
7,764
45 Bas€ $ 761,286 751,719 956,285 1,200,937 't,27o,927 1,135,434 813,607
46
42 0 878,814 2,198,386 834,126 283,952
$ (761,244) (751,71e) (77,471\ 997,449 (436,801) (8s1,482) (805,843)
$ 2,866,223 7,331,128 12,723,428 13,725,698 7,830,785
50 Actual (incl. Net Metering & Raft River $ 10,572,548 10,908,936 11,681,713 12,831,995 12,662,857 12,673,490 10,763,930
5l Base $ 4,252,292 4,198,857 5.341,493 6,708,038 7,098,983 6,342,160 4,544,54'l
52 Change From Base $ 6,320,256 6,710,079 6,340220 6,123,957 5,563,874 6,331,330 6,219,389
53 0eferal (Allocated)
54
55 Total Deferal (-6+41+47+s3)
$ 6,004,243 6,374,575 6,023,209 5,817,759 5,285,681 6,014,763 5,908,420
65,200 1.784/15
56
57 Prlnclpal Balances
58 Beginning Balance $ 0 2,a66,223 10,197,351 22,920,779 36,646,477 44,477,262 44,542,462
59 Amount Def€rod $ 2,866,223 7,331,128 12,723,428 13,725,698 7,830,785 65,200 1,784,415
60 Ending Balance $ 2,866,223 10,197,35'1 22,920,779 36,646,477 44,477,262 44,542,462 46,326,877
61
62 lnterest Balances
63 Accrual thru Prior Month
64 lntersst @ 1% perYear
$
$
$
000 9.915
9,9'15
20,537
0
30,452
28,468
0
58,919
23,853
0
82,773
14,692
0
97,4U
14,O14
065
66 Total Cur€nt Month lnteresl
70 True.Up of the True.Up
71 Tru6-Up Revenues (Collections)
73 Boginning Balance
74 Adjustmonts:75 2012-13 PCA Transfer (ON 32821 )76 Rov€nue Sharing ON 3282'l
77
62,204,982 00 (7,166,126)
00(5,969) 0
45,753,028 40,984,943
0000
$
s
s
$
(3,426,815) (3,833,037) 11,751,527]. 5,24O,O25 5,554,916 4,806,2'13 3,532,232
(7,719,349) 57,957,853 54,667,09't 56,458,200 51,265,223
0
0
78 Sub-Total
79 lnterest @ 1ok petYeat
80 Rev€nu6 Applied to lnterest
81 Revenue Appli€d to Balance
Level of Customer Sharing
ldaho Jurisd. Energy Allocator
Load Change Adjustm€nt Rate
lnterest Rate
Forecast Rate
$ 45.405 42.326
$ 54,485,633 50,791,128 54,661,',122 56,458,200 51,265,223 45,753,028 40,984,943
45,551 47.O49 42,721 34.124 34.154$ 45,405 42,326 45,551 47,049 42,721 38,128 34,154
s (3,472,220\ (3,875,364) 11,797,O78) 5,192,977 5,5'12,'195 4,768,086 3,4e8,078
82 True-Up of the True-Up Balsnce S 57,957,853 54,667,091 56,458,200 51,265,223 45,753,028 40,984,943 37,486,865
Note: Nagative amounts indicate benefit to ratepayers
oh 95.h 95%o/o 95.0% 95.0%$/MWh 17.64 17.64oa 1.oo% 1.00%
$/MWh 5.0990 5.0990
95%
95.0%
17.U
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8.2580
95%
95.0%
17.64
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95%
95.0%
17.64
1.00%
8.2580
95% 95o/o95.0% 95.00/617.u 17.U1.00% 1.000/68.2580 8.2580
Attachment C
Case No. IPC-E-14-05
Staff Comments
05/16114 Page I of2
TRUE.UP CALCULATIONS FOR 2013 .2014
FOR
IDAHO POWER COMPANY PCA
cAsE NO. |PC-E-14-05
(Base Costs are Redistributed)
DESCRIPTION
20't3Units NOV
201 3
0Ec
20't4
JAN
2014
FEB
2014
I\,4AR TOTALS
Actual ldaho Jurisd. Sales'MWh 938,372 1,093,779 '.t,180,245 1,111,808 950,799 12,944,522
MWh 1,131,972 1,358,395 1,346,312 1,139,208 1,134,875 15,531,137
$ 512,319 1172,484J 1,132,559 983,501 1,259,478 (643,172)
Forecast Rate $/lilwh I 258 8.258 8.258 8.258 8.258Revenuo $ 7,749,076 9,032,427 9,746,463 9,181,310 7,851,698 101,039,775
Lo.d Chango Adjustment
Actual SystemFimLoad-Adjusted MWh 1,102,529 1,368,173 1,282j08 1,083,454 1,063,476 '15,567,598
Nomalizod Fim Load
Load Chanse MWh (29.043) 9,778 (64,204) (55,754) (71,399) 36,461
Expense Adjustment
Non-QF PCA
ACTUAL:
Water L6ases
Fuel Exp€ns6 - Coal
Fuel Expense - Gas
Non-Firm Purchases
Third Party Transmission
Surplus Sales
Hoku Firsl Block Energy
33,300
$ 15,084,510 16,190,309 't7,881,323 ',t4,983,221 8,170,369 160,995,670$ 4,857,341 8,159,706 6,989,544 5,657,873 '1,532,113 59,228,806$ 6,923,618 9,030,513 4,052,609 4,854,879 3,874,439 78,523,687$ 346,526 343,673 338,568 325,776 327,362 5,760,7'18$ (9,125,878't 0,451,787) (8,38s,471) (9,811,088) (1o,813,742t (66,784,731)
$000000
Expense Adiustmsnt $ 512,319 ('172,484) 1,132,559 983,501 1,259,478 (643,172)
Sub-Total $ I 8,598,435 26,099,929 22,009,131 17,027,462 4,350,020 237,787,389
BASEI
Water for Power (Leases)
Fuel Expens6 - Coal
Fuel Expense - Gas
Non-Firm Purchases
Third Party Transmission
Hoku First Block Energy
133,301 '1,828,640
Surplus Sales S (8,377,841) (9,897,636) (10,974,199) (10,069,488) (9,106,021) (124,916,'153)
Sub-Total $ 8,443,158 9,974,804 11,059,75e 10,147,996 9,177,013 125,890,058
Change From Base $ 10,155,277 16,125,125 10,949,372 6,879,466 (4,826,993) 111,897,331
EmissionAllowancesalesoredit $ 0 0 0 0 0 (24,000)
Renewable Energy Credit Sales $ (57,748) 329 (397,331) (657,345) (264,940) (1,874,892)
sub-Torat 10,097,529 16,125,454 10,552,041 6,222,121 (5,091,932) 109,998,439
Deferal (Shared and Allocated)
$ 122.643 144.891 160.651$ '11,2'13,235 13,247,390 14,688,304 13,477,403 12,187,860 167,192,743$ 3,483,'108 4,114,967 4,562,550 4,186,415 3,785,851 5't,934,201$ 3,052,258 3,605,958 3,998,176 3,668,568 3,317,552 45,510,094$ 554,'113 654,633 725,838 666,000 602,275 8,262,000$ (1,604,358) (1,895,399) (2,101,561) ('1,928,309) (1,743,805) (23,921,467t
5,615,464 (4,595,469) 99,273,591
Demand Response lncentive Pmts.
Actual $
Base $ 754,664 891,565 988,540 907,045 820,257 11,252,266
$ 9,113,020 14,553,223 9,523,217
0 10 (5,880) 0 o 4.197.214
$ (754,664) (891,555) (e94,420) (907,045) (820,257\ (7,05s,0s2)
$ 5,556,020 5,820,701 4,532,549 5,189,462 4,1 16,675 66,644,057
QF Defenal
Actual (incl. Net Metering & Raft River $ 10,063,745 '11,107,040 10,292,764 '10,529,045 8,9'15,030 133,003,093Base $ 4,215,303 4.979,987 5,521,659 5,066,454 4,58'1,687 62,851,454
Change From Base $ 5,848,442 6,127,053 4,771,105 5,462,591 4,333,343 70,151,639
Deferral (Allocated)
Total Defensl ($+41+47+53)$ 6,165,299 10,449,S41 3,314,883 716,570 (9,150,749) 57,422,822
Prlnclpal Ealances
Beginning Balance
lnterest Balancos
Accrual thru Prior Month
lnterest @ 'lyo per Yeat
lnterest Accrued to Oate
Ealanca (True.UD &
True.Up of the True-Up
True-Up R€v6nues (Collections)
Beginning Balance
Adjustments:
2012-13 PCA Transfer (ON 32821)
Revenue Sharing ON 3282'l
46,326,877 52,492,176 62,942,117
22.047 30,262 37,226
$ 111,478 129,650 151,697 181,959 2'19,185$ 18,172
0
0
0
0
0
0
0
0
$
$
s
46,869 266,054
3,301,969 3,826,256 4,120,942 3,887,370 3,335,162 28,593,706
37,486,865 34,216,'135 30,418,393 26,322,799 22,457,365 (7,719,349)
o 62,204,982o (7,172,095)
66,257,000 66,973,570
PriorMonth'slnterestAdi. S 0 0 0 0 0 0
Total Curent l\,lonth lnterest $ 18,172 22,047 30,262 37,226 46,869 266,054
Sub-Tot8l
lnterest @ 1oh pet Year
Revenue Applied to lnterest
Revenue Applied to Balance
True-Up of the True-Up Balance
31,239 28,51331,239 28,5133,270,730 3,797,742
34.216.'135 30.418.393
$
$
s
$
$
37,486,865 34,216,135 30,418,393 26,322,799 22,457,365 47,313,53825,349 21,936 14,7',t425,349 21,936 ',18,714 421,0854,095,593 3,865,435 3,3'16,448 28,172,62126,322,799 22,457,365 19,140,917 19,140,917
Note: Negative amounts indicate benefit to ratepay€rs
Level of Customer Sharing
ldaho Jurisd. Energy Allocator
Load Change Adjustment Rate
lnterest Rate
Forecast Rate
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95.00/6
17 64
'1.00%
8.2580
95 00/6
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1.00%I 2580 Attachment C
Case No. IPC-E-14-05
staff comments
05116114 Page2 of 2
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Staff Comments
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.7 Case No. IPC-E-14-05
Staff Comments
0slt6/14
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Attachment G
Case No. IPC-E-14-05
StaffComments
05/r6/14
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Case No. IPC-E-14-05
StaffComments
05/t6lt4
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Attachment I
Case No. IPC-E-14-05
Staff Comments
05/t6/14
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Attachment J
Case No. IPC-E-14-05
Staff Comments
05lt6l14
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Case No. IPC-E-14-05
Staff Comments
05116114
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS I6TH DAY OF MAY 2014,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAF'F, IN
CASE NO. IPC-E-14-05, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING:
LISA D NORDSTROM
IDAHO POWER COMPANY
PO BOX 70
BOrSE ID 83707-0070
E-MAIL: [e-mail]
dockets@idahopower. com
PETER J. RICHARDSON
RICHARDSON ADAMS PLLC
5I5 N. 12TH STREET
PO BOX 7218
BOISE, TD 83702
E-MAIL: [e-mail]
BENJAMIN J. OTTO
IDAHO CONSERVATION LEAGUE
7IO N. 6TH STREET
BOISE, ID 83702
E-MAIL: [e-mail]
ANTHONY YANKEL
29814 LAKE ROAD
BAY VILLAGE, OH 44104
E-MAIL : [e-mail]
TIMOTHY E TATUM
GREG SAID
IDAHO POWER COMPANY
PO BOX 70
BOrSE ID 83707-0070
E-MAIL: [e-mail]
[e-mail]
DR. DON READING
6070 HILL ROAD
BOISE,ID 83703
E-MAIL : dreadine(amindspring.com
ERIC L. OLSEN
RACINE, OLSON, NYE, BUDGE &
BAILEY, CHARTERED
2OI E. CENTER
PO BOX 1391
POCATELLO, ID 83204-1391
E-MAIL: [e-mail]
CERTIFICATE OF SERVICE