20130517Comments.pdf

KARL T.KLEIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
P0 BOX 83720
BOISE,IDAHO 83 720-0074
[phone]
IDAHO BAR NO.5156
Street Address for Express Mail:
472 W.WASHINGTON
BOISE,IDAHO 83702-5918
Attorney for the Commission Staff
•1
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I —
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT (PCA)RATES FOR
ELECTRIC SERVICE FROM JUNE 1,2013
THROUGH MAY 31,2014.
)
)CASE NO.IPC-E-13-10
)
)COMMENTS OF THE
)COMMISSION STAFF
)
The Staff of the Idaho Public Utilities Commission comments as follows on Idaho Power
Company’s Application for authority to implement Power Cost Adjustment (PCA)rates for
electric service from June 1,2013 through May 31,2014.
BACKGROUND
On April 15,2013,Idaho Power Company filed its annual Power Cost Adjustment (PCA)
Application.The Company asks for an Order:(1)approving an update to Schedule 55 reflecting
a $140.4 million increase in the PCA rates now in effect;(2)approving the Company’s
determination of the 2012 revenue sharing amounts to be shared with customers;and
(3)implementing one of two proposed Schedule 55 PCA rates,effective June 1,2013 through
May 31,2014,which would allow the Company to collect the $140.4 million over one or two
years.Recovery in a single year would increase Idaho customer rates an average of 15.3 percent.
Recovery over two years under the Company’s Rate Mitigation Proposal would increase rates an
average of 9.6 percent in the first year and leave approximately $52.5 million for recovery in the
STAFF COMMENTS 1 MAY 17,2013
second year along with any amounts that may be surcharged or rebated to customers as part of
the normal PCA process in that year.
IDAHO POWER COMPANY’S FILING
This year the PCA rate for each class combines the three traditional PCA components
(forecast,true-up,and reconciliation)with a fourth,“revenue sharing”component.These four
components are discussed below
Traditional PCA Components
The traditional annual PCA mechanism is comprised of three components:1)a
“forecast”or projection that estimates the difference between power supply costs embedded in
base rates and the coming year’s power supply costs;2)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 3)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.
1.The Forecast.Forecasted power supply costs for the coming year are based on inputs to
the Company’s most recent Operating Plan.The difference between forecasted and base
power supply cost is calculated to be approximately $110 million.The power supply cost
difference is converted to a cents-per-kilowatt hour (0/kWh)rate by dividing the power
costs by projected energy sales.Idaho Power calculates this rate to be 0.8258 0/kWh.
This is the single largest rate component in this year’s PCA.
2.The True-Up.The true-up amount is the difference between forecast and base power
supply costs and revenues from the forecast rate during the previous year.The previous
year’s PCA amount is not precisely recovered because the forecast is never 100%
accurate.The true-up amount is also converted to a 0/kWh rate by dividing by projected
energy sales.Idaho Power calculates the true-up amount to be $62.2 million,which is
expected to be recovered by applying a true-up rate of 0.4622 0/kWh.This component is
largely due to what turned out to be an inaccurate forecast last year.
3.The Reconciliation.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 against
the amounts set for recovery.Any difference is carried into the following year’s true-up
reconciliation along with the true-up difference.Idaho Power calculates the
STAFF COMMENTS 2 MAY 17,2013
reconciliation ofthe true-up amount and rate to be a credit to ratepayers of $7.7 million
and -0.0574 0/kWh,respectively.
These three traditional PCA rate components combine for a 2013/2014 PCA rate
surcharge of 1.2306 0/kWh (0.825 8 +0.4622 -0.0574).The implementation of this rate would
recover traditional PCA costs in one year.
Revenue Sharing
Besides the three traditional components described above,a fourth,“revenue sharing”
component applies to this year’s PCA.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 Equity (ROE)exceeded 10.5 %in the years 2009 through
2011.If revenue sharing was triggered,the Company was to share 50%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 9.5%and 10.5%.Revenue sharing was
triggered for the years ending December 31,2011 and 2012.
Order No.32424 modified the revenue sharing mechanism and extended it through 2014.
This Order reduced the sharing level to 10%,with equal sharing between customers and the
Company when the ROE falls between 10%and 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
10.5%,the earnings above 10.5%continue to be shared but customers receive 75%of the
earnings above 10.5%.The customer share of earnings above 10.5%will be applied to the
Company’s pension balancing account.This revenue sharing contribution reduces amounts that
the Company would otherwise be allowed to collect from customers.
In this year’s filing,the Company calculates $21.8 million of revenue to be shared with
customers.The offset to the PCA is $7.2 million and the remaining $14.6 million is to be
applied to Idaho Power Company’s pension balancing account.Idaho Power proposes to spread
PCA revenue sharing credit to customer classes on a uniform percent of base revenue basis and
use it to reduce PCA energy rates.These class specific energy credits result in a different
combined PCA/Revenue Sharing energy rate for each customer class.These proposed rates are
shown on Company Exhibit No.4,Column B.For the four special contract customers,Idaho
Power proposes that they each receive a different,flat-monthly credit during the PCA year.The
STAFF COMMENTS 3 MAY 17,2013
proposed credits are:Micron -$15,058.46;Simplot -$4,599.49;DOE -$5,943.87;and Hoku -
$0 (Company Attachment No.1).These rates are included in Tariff Schedule No,55,which is
proposed to be effective June 1,2013 and remain in effect for one year.
Rates
Idaho Power Company presents two rate proposals:(1)a traditional rate proposal that
designs rates to recover all PCA amounts in a single year (June 1,2013 through May 31,2014);
and (2)a rate mitigation proposal that spreads PCA recovery over two years.Both proposals
design rates to recover $140.4 million more than current rates.
The Company prefers the traditional,single year recovery plan.The single year recovery
plan causes combined PCA/Revenue Sharing increases as shown in Attachment 3,pages 1 and 2
to the Company’s Application.This plan increases revenue 15.3%on average and increases
residential revenue 12.5%.
The Company’s rate mitigation proposal spreads recovery of $140.4 million over two
years.In the first year the Company would recover $87.9 million,which leaves $52.5 million for
recovery in the following PCA year.First year increases under the Company’s rate mitigation
proposal are shown in Attachment 3,pages 3 and 4 to the Company’s Application.The average
first year increase is 9.6%and the average residential customer increase is 8.0%
STAFF AUDIT AND ANALYSIS
A.The PCA Forecast or Projection
Operating Plan inputs used to forecast power supply costs are the most current
information available to the Company when its filing is prepared.The forecast considers many
factors,including 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)comprised 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
STAFF COMMENTS 4 MAY 17,2013
shared between the Company and its customers.The entire difference in PURPA Qualifying
Facility (QF)contracts is passed on to customers.1
Attachment B shows Staffs calculation of the PCA rate components.Lines 1 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 95/5 sharing.Lines 2
through 8 show this calculation.Line 8 shows the first component of the forecast rate to be
0.3858 0/kWh.This rate element captures the effects of expected poor water conditions,which
are only 60%of average in the Hells Canyon Complex.It also includes the effects of continued
low market prices on off-system sales revenue,which is an offset to power supply costs,and the
loss of all revenue associated with Hoku first block energy sales.
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,that are
passed through to customers without sharing.These amounts are almost entirely PURPA QF
contract costs.This second rate element is 0.4889 0/kWh as shown on line 12.These above-
base PURPA expenses are neither new to the PCA this year nor unexpected.The PURPA base
was not updated in the Company’s last general rate case even though PURPA costs had
substantially increased.This knowingly left a large amount of PURPA costs to be included in
future PCA’s until these costs are moved into base rates in some future general rate case.The
growth in PURPA costs has slowed substantially.While the Idaho customer share of above-base
PURPA costs is expected to be approximately $65 million,the year over year growth,last year to
this year,was just $2.1 million.
The third element of the forecast rate component allows Idaho Power to capture the
difference between base and actual Demand Response 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 is shown on line 16 to be
-0.0489 0/kWh.This negative component indicates an expected reduction in these costs.
The above three elements combine to produce the PCA forecast rate component of
0.82580/kWh shown on line 18.The forecast rate component is by far the largest part of this
year’s PCA rate increase.Staff has reviewed the Company’s forecast rate calculations and
A QF is a generating facility that qualifies for QF status under PURPA and 18 CFR Part 292 and has obtained
certification of its QF status.
STAFF COMMENTS 5 MAY 17,2013
verifies that the calculations are correct.Staff also points out that any errors in the forecast are
trued up in the following year’s PCA.
B.The PCA True-up
The PCA true-up difference is netted against the amount collected from the application of
the previous year’s forecast rate.This difference represents the PCA true-up deferral balance.
This deferral balance is divided by expected jurisdictional energy sales to produce the true-up
rate component.
Page 1,lines 4 through 90 of Company Exhibit No.3 calculates a true-up deferral amount
of $62.2 million.Attachment C contains Staffs verification of the Company’s true-up deferral
calculations.Staff finds the Company’s calculation as shown in Exhibit No,3 to be correct.
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 1,2012
through March 30,2013).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 RMC minutes were also reviewed.
The large true-up balance,$62.2 million,indicates that the prior year’s forecast was
inaccurate.That forecast assumed runoff would come in the normal runoff period.But the
runoff came early,with a substantial part of it occurring in April.Reservoir storage in April
must be maintained below established levels as required by the Corps of Engineers for flood
control purposes.These flood control constraints did not allow Idaho Power to store water for
generation later in the summer.The runoff was passed down stream.The Company generated
power with all of the water that would go through the turbines and received a very low price for
the sale of the excess power.The streamfiow that exceeded the turbines’capacity was spilled
with no benefit accruing to Idaho Power or its customers.
The PCA true-up component includes the following items:
1.Load Change Adjustment.This year’s true-up calculation includes a negative load
change adjustment of $1,056,017.Actual loads during the true-up year were below
normal loads in 6 of 12 months.The actual load for the PCA year was below normal by
64,652 MWh.This represents a 0.42%decline in load.The load change adjustment is
the product of the negative load growth and the load change adjustment rate (LCAR)of
$18.16/MWh for the months of April through June 2012,and $17.64/MWh for July
STAFF COMMENTS 6 MAY 17,2013
through March 2013.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 $1,056,017 (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.
2.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 yea?s PCA deferral
balance includes actual water lease expenses of $2,295,597.The amount included in base
rates is $1,828,640.The difference of $466,957 is included in the deferral balance.This
increase in water lease expenses from base expenses is a cost to customers and is subject
to jurisdictional allocation and sharing.
3.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 2012 to March 2013 audit period,the
total coal expense for the three plants is $143,733,017.The total coal expense included
in base rates is $167,308,029.This year’s PCA deferral balance includes a difference
between costs currently included in rates and actual costs of $23,575,012.This decrease
in coal costs from base costs is a benefit to customers and is subject to jurisdictional
allocation and sharing.
4.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 located at Mountain Home,Idaho;and Langley Gulch,located near New
Plymouth,Idaho.Langley Gulch was included in base rates beginning in July 2012.For
the April 2012 through March 2013 audit period,the total variable gas and gas
transportation expense for all the gas plants was $31,593,483.The total gas and gas
transportation expense included in base rates is $41,867,730.This decrease in gas
expense from base rates is included in the PCA.This year’s PCA deferral balance
STAFF COMMENTS 7 MAY 17,2013
includes a difference between costs currently included in rates and actual costs of
$10,274,247.This decrease in natural gas expenses from base expenses is a benefit to
customers and is subject to jurisdictional allocation and sharing.Staff notes that the
addition of Langley Gulch has changed the how the Company buys natural gas.In the
past,the cost of the financial hedges for natural gas was less than 1%of the total cost for
natural gas in the PCA.During this PCA period,the financial hedges for natural gas
were about 16%of the total natural gas costs included in the PCA.Staff does not take
issue with the financial hedging activity in the natural gas sales and purchases during this
PCA period.
5.Power Sales and Purchases.Staff reviewed the power purchases and sales in conjunction
with the Company’s Operating Plan.Staff did not find any transaction that was
unreasonable or did not follow the Risk Management Committee recommendations.
These transactions were made with an assortment of credit-worthy 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 31,2013,the Company sold
off-system surplus power totaling $48,751,418.The total surplus sales included
in base rates is $117,833,671.This decrease in the power sales from base rates is
included in the PCA.Actual surplus sales were less than base amounts by
$69,082,254.This decrease in revenues is a cost to customers and is subject to
jurisdictional allocation and sharing.
b.Power Purchases.During the PCA year ending March 31,2013,the Company
made various market power purchases,excluding its PURPA contracts.The total
amount of power purchases is $56,000,484.The amount of power purchases
included in base rates is $50,157,899.Actual power purchases were more than
base amounts by $5,842,585.This increase in purchases is a cost to customers
and is subject to jurisdictional allocation and sharing.
6.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 April 2012 through
March 2013 audit period,the actual third-party transmission expense is $6,245,230.The
STAFF COMMENTS 8 MAY 17,2013
third-party transmission expense included in base rates is $8,262,000.This years PCA
deferral balance includes the difference between actual costs and base costs of
$2,016,770.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.
7.Hoku First Block Energy.In Order No.32426 (Case No.IPC-E-11-08),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
Energy revenues during the current PCA period is $1,197,218.The actual revenues are
less than the amount included in base rates by $22,724,249.This decrease in revenues is
a cost to customers and is subject to jurisdictional allocation and sharing.
8.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.No emission allowance sales occurred in the April
2012 through March 2013 PCA period.This is understandable with existing market
conditions.
9.Renewable Energy 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 $2,678,444 and is a benefit to customers.
10.Actual PURPA Purchases Including Net Metering and Raft River Expenses.For the
April 2011 through March 2012 audit period,the actual PURPA expense is
$128,789,373.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
$65,937,919.This amount is a cost to customers and increases the PCA deferral balance.
PURPA contracts are not currently subject to sharing,but they are subject to
jurisdictional allocation.
STAFF COMMENTS 9 MAY 17,2013
11.Demand Response Incentive Payments.In Order No.32426 (Case No.IPC-E-11-08),the
Commission determined that Demand Response Incentive 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 2011 to March 2012),the actual Demand
Response Incentive Payments are $14,479,509.The base amount of Incentive Payments
included in base rates during the PCA period is $11,252,266.The difference between the
actual amount and the base amount is $3,227,243 and is a cost to customers.The
Demand Response Incentive Payments are not currently subject to sharing and are
allocated 100%to the Idaho jurisdiction.
In summary,the Idaho customer true-up Deferral Balance is composed of the following:
Load Change Adjustment $1,056,017
Water Leases $466,957
Fuel Expense Coal $(23,575,012)
Fuel Expense —Gas $(l0,274,247)
Surplus Sales $69,082,254
Non-Firm Purchases $5,842,585
Third Party Transmission $(2,0 16,770)
Hoku Energy $22,724,249
Subtotal —Change from Base $63,306,032
Emission Allowance Sales Credit $0
Renewable Energy Credit (REC)Sales $(2,678,444)
Subtotal —Subject to Jurisdictional Allocation &Sharing $60,627,588
Subtotal -After Jurisdictional Allocation and Sharing $54,716,398
Qualifying Facilities —After Jurisdictional Allocation $62,641,023
Demand Response Incentive Payments $3,227,243
Total all Expense Items $120,584,664
Revenue from the Forecast $58,559,529
Deferral Balance $62,025,135
Interest on the Deferral Balance $179,848
Deferral Balance (Credit)$62,204,983
STAFF COMMENTS 10 MAY 17,2013
The Company-proposed true-up rate is 0.4622 0/kWh.Staff calculates the same rate as
the Company,which is shown on Staff Attachment B,line 23.
C.The Reconciliation ofthe 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 both Idaho Power Company and
its customers that the amount approved for recovery is the amount actually recovered.
The reconciliation of the true-up included the following amounts:
2011-12 Forecast True-Up ($17,646,658)
2010-11 True up of the True-Up Balance ($5,165,169)
Revenue Sharing (Order No.32558)($27,200,636)
Net Amount Set for Recovery/(Refund)($50,012,463)
Collection from True-Up Rates $42,610,397
Interest ($317,283)
True-Up Reconciliation (Credit)($7,719,349)
This is the amount recommended for refund by the Company and Staff.Dividing this
refund amount by expected sales produces the true-up reconciliation rate credit of 0.0574 0/kWh.
This calculation is shown on Attachment B,line 25.
D.Revenue Sharing
The Company proposes to offset the proposed PCA rate increase with a $7.2 million
revenue sharing credit.Staff has reviewed and audited the revenue sharing amount and the
allocation of that amount to customer classes.Staff has verified that the amount is correct.
Idaho Power allocated the credit to all customer classes on a uniform percent of revenue basis
using forecasted billing determinants and associated class base revenues just as it did with
revenue sharing amounts in last year’s PCA.This creates a different 0/kWh rate for each rate
schedule.These rates are shown on Attachment D.Within each customer rate schedule the
decrease was assigned to the energy rates.
STAFF COMMENTS 11 MAY 17,2013
COMBINED PCA AND REVENUE SHARING RATES
The uniform 1.2306 0/kWh PCA rate surcharge is the sum of the three traditional PCA
components (0.8258 +0.4622 -0.0574).This new PCA surcharge rate,shown on Attachment B,
line 28,combines with revenue sharing rates shown on Attachment D to produce PCA rates.The
rates are also shown on Schedule 55,which is Attachment 1 to Idaho Power’s Application.
These are the rates for a one-year recovery of the full PCA amount.
Pages 1 and 2 of Attachment E show the percentage increase in the Combined
PCAlRevenue Sharing rates for all Idaho Power customer rate schedules for a one-year recovery
period.Pages 3 and 4 show the customer impacts of the first year of Idaho Power’s rate
mitigation proposal.Pages 5 and 6 show rates and increases by rate schedule to recover only the
carry-over amount of about $52.5 million.In all cases the impacts are measured against all
billed revenue.Increase percentages vary by customer class.The Staff calculations agree with
the Company’s calculations for the two options presented by the Company.
StaffRate Mitigation Proposal
Staff proposes a different rate mitigation option.Staff proposes that the increase be
spread over two years with both annual percentage increases the same.This year’s PCA increase
would be $71.72 million,a 7.84%average increase,and next year’s increase would be $77.36
million which is also a 7.84%average increase.The second year increase amount is calculated
as follows:the 2013 PCA amount to be carried over to the 2014 PCA,plus known costs carried
forward in the PCA until moved into the base,minus the amount to be recovered in the 2013
PCA (140.4—71.72 +80.4—71.72 =77.36).The known costs carried forward are:above base
PURPA costs at $65.4 million,lost Hoku first block energy revenue at $21.6 million,and
decreased Demand Response Incentive Payments of $6.6 million (65.4 +21.6—6.6 =80.4).
These costs will continue to be included in each year’s PCA until they are moved to base rates;
thus,they must be included in 2014 PCA rate calculations.The second year increase assumes
this PCA accurately forecasts water conditions,market prices,fuel prices and loads and other
inputs such that there is no true-up deferral balance next year.It also assumes that next year’s
PCA forecast only shows differences from base for Hoku,PURPA and Demand Response
Incentive Payments.Of course,if there are other net cost increases in next year’s
STAFF COMMENTS 12 MAY 17,2013
PCA,an increase above 7.84%may be required.Attachment F,pages 1 through 4 show Staff’s
calculations.Pages 1 and 2 show rate impacts in the first year and page 3 and 4 show expected
second year rate impacts.
Staff also examined an option that produced equal average 8.86%increases in each of
two years.This analysis included all of the same assumptions used in Staff’s preferred proposal
but it included an additional $30 million in above-base PCA costs in next year’s PCA.These
additional costs could be driven by water conditions,market prices or any other PCA input.
The Company’s rate mitigation proposal,evaluated under the same assumptions included
in Staff’s preferred proposal,produces a first year increase of 9.6 %and a second year increase
of 4.5%.The Company’s proposal is a little less aggressive in controlling rate increases this
year,but it provides some head room to handle additional cost increases next year without a
larger rate increase than proposed this year.
Staff believes that a rate mitigation plan has merit to soften the impact of the greater than
20%increases to some customer classes that would be required to pass these costs through to
ratepayers in a single year.Staff is also hopeful that water conditions and market prices will
return to base levels and/or customers will receive an offsetting revenue sharing benefit.
OTHER PCA ISSUES
Actual True-Up Revenue
In Commission Order No.32552 issued in last year’s PCA case,Case No.IPC-E-12-17,
the Commission ordered the Staff and Company to meet and discuss an issue raised in the case
relating to the revenue credit included in the true-up mechanism.The Commission said,
We also encourage Staff to discuss with the Company Staff’s concerns about
using normalized data versus actual data in the true-up component of the PCA
mechanism.(Order No.32552,p.7).
Since the PCA began,the revenue credit has been the forecast rate multiplied by
normalized Idaho jurisdictional sales as established in a general rate case.This calculation does
not credit the PCA with the actual revenue the Company receives from the application of the
rate.To credit customers with the Company’s actual revenue,the rate must be applied to actual
Idaho jurisdictional energy sales.Over time,Staff has come to believe that the actual revenue
received by the Company should be credited.The Staff and the Company have discussed this
STAFF COMMENTS 13 MAY 17,2013
issue and the Company has agreed to implement the change if approved by the Commission.
The Staff and Company propose to implement the change with the new PCA rates on June 1,
2013.The change would mirror the methodology used to credit actual revenues collected from
the true-up rate components in the reconciliation of the true-up portion of the PCA.The change
in methodology delays the revenue credit for a short period of time while actual kWh sales are
accumulated.
Third Party Transmission Revenue
In the Commission’s Notice in this case,Order No.32796,the Commission invited the
parties to “comment on the issue of whether Idaho Power’s PCA calculation should continue to
include transmission expenses only or whether both transmission revenue and expense should be
included.”
When transmission expense differences were added to the PCA,the Staff and Company
also discussed including third party transmission revenue differences.Importantly,only
differences were considered,because there is a base amount of both transmission revenue and
expense included in base rates.During the previous discussions,the Staff was persuaded to not
recommend that transmission revenue differences be included.Staff understood that
transmission expense was incurred when another utility’s transmission system was used to
deliver market purchased power to Idaho Power’s native load customers.Transmission revenue,
on the other hand,results from two other utilities wheeling power across Idaho Power’s system
when Idaho Power’s customers do not need the transmission capacity.Transmission expense
was associated with delivering power to native load customers and transmission revenue accrued
from an opportunity to profit from transmission that would have otherwise gone unused.As part
of the give and take of settling a group of issues,the Staff dropped the idea of including
transmission revenue differences.Avista’s PCA and Rocky Mountain’s ECAM both include
transmission revenue differences.After reconsidering the issue,the Staff supports including
transmission revenue differences in the PCA.
Other PCA Attachments
Staff has included two other 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.
STAFF COMMENTS 14 MAY 17,2013
CUSTOMER RELATIONS
Customer Notice and Press Release
Idaho Power’s PCA Application contains both the customer notice and press release.
Staff reviewed both and determined they comply with Procedural Rule 125,IDAPA
3 1.01.01.125.The customer notice was mailed with Idaho Power’s cyclical billings beginning
April 25,2013 and ending May 22,2013.Customers have until May 28,2013 to file comments.
Customer Comments
By May 16,2013,seventeen comments had been received,nearly all from low and fixed
income customers stating that they do not know how they are going to afford higher rates for
power.Many say to just tell the Company “no.”Another recurrent theme in comments is that
customers feel the more they conserve electricity,the higher the rates get.Additionally,one
frustrated customer commented that he lives in an electrically-heated home with no access to
natural gas lines.
Commission Staff conducted informational workshops regarding Idaho Power’s filing.
The workshops were held in Pocatello,Twin Falls,and Boise during the first part of May,2013.
Excluding Staff and Idaho Power employees,a total of nine people attended the three workshops.
STAFF RECOMMENDATIONS
Staff recommends that the Commission approve the revenue sharing amounts proposed
by the Company;specifically,PCA revenue sharing of $7,151,221 and a pension balancing
account contribution of $14,618,532.
Staff recommends that the Company be authorized to recover $140,371,197 above the
revenue currently included in rates.
Staff recommends that the Commission approve Schedule 55 rates that implement the
Staff’s rate mitigation proposal.First-year rates should be designed to recover $71,720,000.The
unrecovered balance would be carried in the balancing account for recovery in the following
year.
Staff recommends that the Commission approve a total first-year PCA rate comprised of
the uniform 0/kWh increase of 0.7205 0/kWh and revenue sharing rates,as shown on
Attachment D to Staffs comments.Staff recommends that these rates be effective June 1,2013
through May 31,2014.
STAFF COMMENTS 15 MAY 17,2013
Respectfully submitted this I 7 ‘day of May 2013.
Karl T.Klein
Deputy Attorney General
Technical Staff:Keith Hessing
Kathy Stockton
Marilyn Parker
i:umisc/comments/ipcel3.lOkkkhklsmp comments
STAFF COMMENTS 16 MAY 17,2013
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2013-2014 PCA -Twenty-First Annual
IPC-E-1 3-10
Staff Case
(a)(b)(C)(d)(e)(f)(g)
Line Description Units Base Forecast Difference Rate
I Forecast 2013-2014:
2 PCA Expense (95%)($)125,890,059 183,104,580
3 Hoku First Block Revenue ($)0
4 Difference ($)183,104,580 57,214,521
5 Sharing Percentage (%)0.95
6 Shared Difference ($)54,353,795
7 Normalized System Firm Sales (MWH)14,088,933
8 Rate for 95 %Items (0/kWh)0.3858 0.3858
9
10 PCA Expense (PURPA at 100%)($)62,851,454 131,731,526 68,880,072
11 Normalized System Firm Sales (MWH)14,088,933
12 Rate for PURPA (0/kWh)0.4889 0.4889
13
14 Demand Response Incentives (100%)($)11,252,265 4,668,960 (6,583,305)
15 Idaho Jurisdictional Sales (MWI-f)13,459,100
16 Rate for Demand Response (0/kWh)(0.0489)(0.0489)
17
18 Total Forecast Rate (0/kWh)0.8258
19
20
21 (MWh)($/MWh)(/kWh)
22
23 True-Up of 2012-2013:62,204,982 13,459,100 4.622 0.4622
24
25 True-Up of the True-Up:(7,719,349)13,459,100 -0.5735 (0.0574)
26
27 PCA Rates:
___________
28 PCA Rate Adjustment From Base (0/kWh)I 1.2306 I
29 PCA Rate Currently in Effect (0/kWh)0.3367
30 Difference -Last Year to This Year (0/kWh)0.8939
31
32 Note:Negative rates and amounts indicate benefits to ratepayers.
33
34
35 Expected PCA Revenues:Rate Energy Revenue
36 ($/MWh)(MWh)
37
38 Forecast Revenue 8.258 13,459,100 111,145,248
39 True Up Revenue 4.622 13,459,100 62,207,960
40 True Up of True Up Revenue (0.574)13,459,100 (7,725,523)
41 Total 12.306 165,627,685
42
43 13,459,100,000 Company Estimate of 2013/2014 Idaho Jurisdictional sales
14,088,933,000 Company Estimate of 2013/2014 normalized system firm sales
NOTES:
Rates are for a one year recovery period
Rates exclude Revenue Sharing
Attachment No.B
Case No.IPC-E-13-1O
Staff Comments
5/17/13
TRUE-UP CALCULATIONS FOR 2012 -2013
FOR
IDAHO POWER COMPANY PCA
CASE NO.IPC-E-13-10
(Base Costs are Redistributed)
24
25
26 BASE:
27 Waterfor Power (Leases)
28 Fuel Expense -Coal
29 Fuel Expense -Gas
30 Non-Firm Purchaaea
31 Third Party Transmission
32 Hoku First Block Energy
33 Surplus Sales
34 Sub-Total
35
________________________
36 Change From Base
37 Emission Allowance Sales Credit
38 Renewable Energy Credit Sales
39 Sub-Total
40
41 Deferral (Shered and Allocated)
42
43 Demsnd Response tncenttve Pmts.
44 Actual
45 Base
46 Change From Base
47 Deferral
48
49 OF Deferral
50 Actusl (md.Net Metering &Raft River)$
51 Base $
52 Change From Base $
53 Deferral (Allocated)$
54
55 Totel Deferrel 1-8+41+47+53)
56
57 Prtnctpsl Bslsnces
58 Beginning Bslsnce
59 Amount Deferred
60 Ending Bslsnce
81
69
70 True-up of the True-up
71 Tme-Up Revenees (Collections)
72
73 Beginning Balance
74 Adjustments:
75 2011-12 PCA Transfer
76 Revenue Sharing ON.32558
77
78 Sub-Total $
79 lnterestl 1%per Year $
80 Revenue Applied to Interest $
81 Revenue Applied to Balance $
82 True-Un of the True-uo Bstsnce $
$(17,646,658)0
$0 (27,200,636)
2012
OCT
Note:Negative amounts indicate benefit to ratepayers Attachment No.C
Case No.IPC-E-13-1O
Staff Comments
5/17/13 Page 1 of 2
2012
Units APR
2012
MAY
2012
JUN
2012
JUL
2012
AUG
2012
SEPT2DESCRIPTION
3 PCA Revenue
4 Normalized Idaho Jurisd.Sales MWh 947,192 953,286 1,100,636 1,338,967 1,416,209 1,282,310 1,028,994
5 Forecast Rate $/MWh 0.445 0.445 5.099 5.099 5.099 5.099 5.099
B Revenue $421,500 424,212 5,612,143 6,827,393 7,221,250 6,538,499 5,246,840
7
8 Losd Chsnge Adjustment
9 Actual System Firm Load -Adjusted MWh 1,078,204 1,285,353 1,511,279 1,771,274 1,630,622 1,206,348 1,076,818
10 Normalized Firm Load MWh 1,047,064 1,271,705 1,393,674 1,744,091 1,586,231 1,279,154 1,096,456
II Load Chsnge MWh 31,140 13,646 117,605 27,183 44,391 (72,606)(21,638)
12 Expense Adjustment $(565,502)(247,846)(2,135,707)(479.506)(763,057)1,284,298 381,694
13
14 Non-OF PCA
15 ACTUAL:
16 Water Leases 0 ‘0 0 0 2,285,800 9,797 0
17 Fuel Expense -CosI 4,872,319 4,527,218 7,652,926 13,033,134 14,670,176 14,201,307 13,655,610
18 Fuel Expense -Gas 1,749,314 1,649,733 700,593 5,261,669 5,696,209 2,775,376 1,957,031
19 Non-Firm Purchases 1,940,890 5,499,156 4,470,374 9,919,525 8,152,830 1,172,271 3,135,992
20 Third Party Transmission 343,732 481,268 897,412 1,142,031 1,122,296 318,667 443,739
21 Surplus Sales (5,146,913)(4,550,444)(1,455,295)(153,567)(717,263)(3,585,476)(5,169,928)
22 Noku First Block Energy (545,550)(545,550)(106,118)0 0 0 0
23 Expense Ad(ustment (565,502)(247,648)(2,135,707)(479,508)(783,057)1,284,298 381,694
Sub-Total $2,648,290 6,813,533 9,994,185 28,723,285 30,626,973 16,176,462 14,384,137
$123,719 122,164 155,409 195,166 206,542 184,523 132,222
$11,347,172 11,204,581 14,253,689 17,644,222 18,864,165 16,870,940 12,089,048
$410,164 405,010 515,225 5,542,657 5,665,695 5,240,531 3,755,157
$4,511,966 4,455,268 5,667,682 4,857,222 5,140,301 4,592,293 3,290,655
$556,976 551,952 702,154 681,790 933,181 833,695 597,393
$(1,616,436)(1,598,098)(2,032,990)(2.553,101)(2,701,896)(2,413,847)(1,729,667)
$(6.267.815)(6.189.053)(7.873.283)(13,332.107)(14.109,103)(12,604.931)(9.032,194)
$9,065,746 6,951,824 11,387,886 13,436,051 14,219,105 12,703,204 9,102,614
$(6,417,456)(2,138,291)(1,393,701)15,267,234 16,407,668 3,473,258 5,281,523
$0 0 0 0 0 0 0
$(906,557)(233,140)(267,301)(365,021)(837,670)(39,334)243
$(7,324,013)(2,371,431)(1,661,002)14,922,212 15,570,198 3,433,925 5,281,766
$(6,609,922)(2,140,216)(1,499,054)13,467,297 14,052,103 3,099,117 4,766,794
$0 0 1,121,364 3,885,012 7,348,157 1,992,162 156,160
$761,266 751,719 956,285 1,200,937 1,270,927 1,135,434 613,607
$(761,286)(751,719)165,079 2,664,075 6,077,230 856,728 (657,447)
$(761,286)(751,719)165,079 2,664,075 6,077,230 856,728 (657,447)
6,407,171 9,535,748 12,481,002 13,480,102 12,259,096 10,777,609 7,634,249
4.252.292 4.198.857 5.341.493 6.708.038 7.098.953 6.342.160 4.544.541
$
$
4,154,879 5,336,891 7,139,509 6,772,064 5,160,113 4,435,449 3,089,706
3,947,135 5,070,046 6,782,533 6,433,461 4,902,107 4,213,676 2,935,222
$(3,545,574)1,753,699 (163,585)15,757,440 17,810,191 1,631,023 1,797,729
$(3 845 574)(2 091 675)(2 255 259)13 502 180 31 312 371 32 943 394 34 741 123
0 (3,545,574)(2,091,675)(2,255,259)13,502,180 31,312,371 32,943,394
(3.845.574)1.753.899 (163.585)15.757.440 17.810.191 1.631.023 1.797.729
62 Interest Balances
63 Accrual thru Prior Month $0 0 5,913 19,025 28,666 36,291 43,001
64 lntsrsst@ 1%per Year $0 5,913 13,099 10,477 7,555 6,710 7,337
65 Prior Month’s lntsrestAd(.$0 0 16 (839)70 0 0
66 Total Current Month Interest $0 5,913 13,115 9,636 7,625 6,710 7,337
67 Interest Accrued to Date $0 5,913 19,028 28,666 36,291 43,001 50,338
68 Bxlsnce (True-Up &Interest)$(3,845,574)(2,065,762)(2,236,232)13,530,846 31,348,662 32,986,395 34,791,461
$(313,763)(344,815)(1,611,927)(5,441,917)(5.716,503)(5,092.169)(3,915,581)
$(5,165,169)(22,517.074)(49,414,326)(47.843,575)(42,441,530)(36,760,395)(31,695,860)
0 0 0 0 0
0 0 0 0 0
(22,811,827)(49,717,710)(49.414.326)(47,B43,578)(42,441,530)(36,760,395)(31.698.860)
(19,010)(41,431)(41,179)(39,870)(35,368)(30,634)(26,416)
(19,010)(41,431)(41,179))39,870)(35,368)(30,634)(26.416)
(294,753)(303,384)(1,570,748)(5,402,047)(5,681,135)(5,061,535)(3.892,165)
(22.517.074)(49.414.326)(47.843.578)(42.441.530)(36.760.395)(31 .698.660)(27.806.695)
TRUE-UP CALCULATIONS FOR 2012 -2013
FOR
2 DESCRIPTION
3 PCA Revenue
4 Normalized Idaho Jurisd.Sales
S Forecact Rate
13
14 Non-QF PCA
15 ACTUAL:
16 Water Leases
17 Fuel Expense -Coal
18 Fuel Expense-Gas
19 Non-Firm Purchases
20 Third Party Transmission
21 Surplus Sales
22 Hoku First Block Energy
23 Exoense Adiustment
24
57 PrIncipal Balances
58 Beginning Balance
59 Amount Deferred
60 Ending Balance
61
62 Interest Balances
63 Accrual thru Prior Month
64 Interest @ 1%per Year
65 Prior Months InterestAdi.
66 Total Current Month Interest
67 Interest Accrued to Date
68 Balance (True-Up &Interest)
69
70 True-Up of the True-Up
71 True-Up Revenues (Collections)
72
73 Beginning Balance
74 Adjustments:
75 2011-12 PCA Transfer
76 Revenue Sharing ON.32558
77
78 Sub-Total
79 Interest @ 1%per Year
80 Revenue Applied to Interest
81 Revenue Applied to Balance
82 True-Up ofthe True-Up Balance
IDAHO POWER COMPANY PCA
CASE NO.IPC-E-13-10
(Base Costs are Redistributed)
2012 2012 2013
Units NOV DEC JAN
MWh 928,924 1,055,150 1,152,449 1,052,464
SIMWh 5 099 5 099 5099 5099
2013
MAR TOTALS
2013
FEB
6 Revenue $4,736,583 5,380,210 5,876337 5366,514 4,908,048 58,559,529
7
8 Load Change Adjustment
9 Actual System Firm Load -Adjusted MWh 1,068,915 1,226,268 1,431,936 1,105,285 1,074,183 15,466,485
10 Normalized Firm Load MWh 1,131,972 1,358,395 1,346,312 1,139,208 1,134,875 15,531,137
11 Load Change MWh (63057)(132,127)85,624 (33,923)(60,692)(64,652)
12 ExpenseAdjustment $1,112,325 2,330,720 (1,510,407)598,402 1,070,607 1,056,017
962,551 13,219,132
5099
0 0 0 0 0 2,295,597
14,720,923 16,083,420 15,177,603 12,917,045 12,221,336 143,733,017
1,020,298 1,841,479 5,292,403 1,097,332 2,352,041 31,593,483
5,262,006 6,130,650 5,006,440 3,045,528 2,264,822 56,000,484
444,241 183,356 296,719 281,716 289,831 6,245,230
(4,547,401)(7,700,390)(3,358,763)(6,332,412)(5,983,545)(48,751,418)
0 0 0 0 0 (1,197,218)
1.112.325 2.330.720 (1.510.4071 598.402 1.070.607 1.056.017•
-Sub-Total 18,012,392 18,869,235 20,903,996 11,607,612 12,215092 190975,192
25
26 BASE:
27 WaterforPower(Leases)$122,643 144,891 160,651 147,407 133,301 1,828,640
28 Fuel Expense-Coal $11,213,235 13,247,390 14,688,304 13,477,403 12,187,860 167,308,029
29 Fuel Expense-Gas $3,483,108 4,114,967 4,562,550 4,186,415 3,785,851 41,867,730
30 Non-Firm Purchases $3,052,258 3,605,958 3,998,176 3,668,568 3,317,552 50,157,899
31 Third Party Transmission $554,113 654,633 725,838 666,000 602,275 8,262,000
32 Hoku First Block Energy $(1,604,358)(1,895,399)(2,101,561)(1,928,309)(1,743,805)(23,921,467)
33 Surplus Sales $(8,377,841)(9,897,636)(10,974,199)(10,069,488)(9,106,021)(117,833,671)
34 Sub-Total $8,443,158 9,974,804 11,059,759 10,147,996 9,177,013 127,669,160
35
36 Change From Base $9,569,234 8,894,431 9,844,237 1,459,616 3,038,079 63,306,032
37 Emission Allowance Sales Credit $0 0 0 0 0 0
38 Renewable Energy Credit Sales $(30,884)496 224 200 299 (2,678,444)
39 Sub-Total 9,538350 8,894,927 9,844,461 1,459,816 3,038,378 60,627,588
40
41 Deferral (Shared and Allocated)$8,608,361 8,027,672 8,884,626 1,317,484 2,742,136 54,716,398
42
43 Demand Response Incentive Pmts.
44 Actual $140 (23,548)21 0 40 14,479,509
45 Base $754,664 891,565 988,540 907,045 820,257 11,252,266
46 Change From Base $(754,524)(915,113)(988,519)(907,045)(820,217)3,227,243
47 Deferral $(754524)(915,113)(988,519)(907,045)(820,217)3,227,243
48
49 OF Deferral
50 Actual (md.Net Metering &Raft River)$10,037,769 12,504,335 9,218,136 11,667,999 10,786,158 128,789,373
51 Base $4,215,303 4,979,987 5,521,659 5,066,454 4,581,687 62,851,454
52 Change From Base $5,822,466 7,524,348 3,696,477 6,601,545 6,204,471 65,937,919
53 Deferral (Allocated)$5,531,343 7,148,130 3,511,654 6,271,468 5,894,248 62,641,023
54
55 Total Deferral (.6+41+47+53)$8,648,596 8,880,479 5,531,423 1,315,393 2,908,120 62,025,135
56
$34,741,123 43,389,719 52,270,199 57,801,621 59,117,015
$8,648,596 8,880,479 5,531,423 1,315,393 2,908,120 62,025,135
$43,389,719 52,270,199 57,801,621 59,117,015 62,025,135
$50,338 61,842 79,290 103,375 136,537
$11,506 17,450 24,358 33,168 43,311 180,884
$121 (21 (2731 (61 0 (1.0361
.$11,504 17,448 24,085 33,162 43,311 179,848
$61,842 79,290 103,375 136,537 179,848
--$43,451,561 52,349,489 57,904,996 59,253,552 62,204,982 62,204,982
$(3,573,044)(3,807,905)(4,453,037)(4,561,006)(3,775,730)(42,610,397)
$(27,806,695)(24,256,823)(20,469,132)(16,033,153)(11,485,508)(5,165,169)
$0 0 0 0 0 (17,646,658)
$0 0 0 0 0 (27,200,636)
Note:Negative amounts indicate benefit to ratepayers
$(27,806,695)(24,256,823)(20,469,132)(16,033,153)(11,485,508)(50,012,463)
$(23,172)(20,214)(17,058)(13,361)(9,571)
$(23,172)(20,214)(17,058)(13,361)(9,571)(317,283)
$(3,549,871)(3,787,691)(4,435,979)(4,547,645)(3,766,159)(42,293,114)
$(24,256,823)(20,469,132)(16,033,153)(11,485,508)(7,719,349)(7,719,349)
Attachment No.C
Case No.IPC-E-13-1O
Staff Comments
5/17/13 Page2of2
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24
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f
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t
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s
:
1
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s
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n
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a
l
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r
v
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c
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2
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s
t
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3
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s
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4
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s
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3
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2
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4
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9
6
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7
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12
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13
To
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24
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20
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:
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1
2
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3
3
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4
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5
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7
6
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9
7
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15
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19
9
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24
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40
11
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41
12
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42
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6
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%
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3
,
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,
8
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7
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,
8
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8
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,
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2
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9
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8
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%
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r
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f
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s
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h
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of
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r
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s
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h
)
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l
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h
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d
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t
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l
20
1
3
20
1
3
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l
20
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13
To
t
a
l
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f
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r
m
Ta
r
i
f
f
s
48
6
,
8
5
3
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4
4
1
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,
7
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5
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1
7
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5
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1
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6
2
%
14
Sp
e
c
i
a
l
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n
t
r
a
c
t
s
:
15
Mi
c
r
o
n
26
1
58
7
,
8
6
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,
6
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9
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6
,
4
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5
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1
4
4.
5
0
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,
2
4
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,
2
8
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,
7
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7
0
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5.
0
5
12
.
2
7
%
16
J
RS
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m
p
l
o
t
29
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2
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,
0
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,
2
3
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7
9
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9
7
%
17
DO
E
30
1
23
6
,
9
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4
,
4
9
3
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8
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4.
4
2
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,
3
0
7
,
4
9
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1
,
7
8
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4.
9
7
12
.
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%
18
Ho
k
u
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t
a
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l
32
0
0
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0.
0
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0
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19
To
t
a
l
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e
c
i
a
l
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n
t
r
a
c
t
s
3
1,
0
1
7
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5
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9
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8
45
,
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2
5
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5
9
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4.
4
3
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,
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1
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1
2
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,
7
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9
4.
9
9
12
.
4
4
%
20
To
t
a
l
Id
a
h
o
Re
t
a
i
l
Sa
l
e
s
48
6
,
8
5
6
13
,
4
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9
,
0
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,
6
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98
6
,
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7.
3
3
77
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3
6
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9
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7.
8
4
%
(1
)
Ju
n
e
1,
20
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3
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y
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20
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r
e
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a
s
t
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d
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s
t
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r
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tr
j
P
0
0 0 0 0
Un
i
f
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r
m
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r
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f
f
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e
s
:
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h
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r
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p
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n
y
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l
c
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l
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t
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e
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p
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t
e
of
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h
o
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f
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Ju
n
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1,
2
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4
Su
m
m
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p
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Ra
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s
9,
19
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an
d
24
Di
s
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t
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20
1
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A
to
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p
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d
20
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4
PC
A
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(1
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1,
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1
3
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Ma
y
31
,
20
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4
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r
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PC
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s
t
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r
(T
h
Z
00
-
.,
:
0
C
Li
n
e
No
Ta
r
i
f
f
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s
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p
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e
r
a
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e
No
r
m
a
l
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d
Cu
r
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e
n
t
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j
u
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h
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m
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of
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To
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s
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to
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l
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d
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s
t
o
m
e
r
s
(1
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(k
W
h
)
(1
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Re
v
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n
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r
kW
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n
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9S
32
,
1
8
0
3,
1
3
3
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3
4
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9
6
9
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1
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5
5
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6.
7
3
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7
,
8
7
6
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6
0
8
$2
2
8
,
8
7
8
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1
5
9
7.
3
0
8.
4
7
%
9P
19
2
44
7
,
5
2
2
,
1
4
0
$2
6
,
2
6
9
,
4
3
2
5.
8
7
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6
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%
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2
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4
4
9
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7
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9
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8
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3
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5
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0
6.4
0
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6
5
%
1
La
r
g
e
Ge
n
e
r
a
l
Se
c
o
n
d
a
r
y
2
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r
g
e
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n
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r
a
l
Pr
i
m
a
r
y
3
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r
g
e
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n
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r
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l
Tr
a
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s
m
i
s
s
i
o
n
4
To
t
a
l
Sc
h
e
d
u
l
e
9
6
La
r
g
e
Po
w
e
r
Se
c
o
n
d
a
r
y
7
La
r
g
e
Po
w
e
r
Pr
i
m
a
r
y
8
La
r
g
e
Po
w
e
r
Tr
a
n
s
m
i
s
s
i
o
n
9
To
t
a
l
Sc
h
e
d
u
l
e
19
11
Ir
r
i
g
a
t
i
o
n
Se
c
o
n
d
a
r
y
12
Ir
r
i
g
a
t
i
o
n
Tr
a
n
s
m
i
s
s
i
o
n
13
To
t
a
l
Sc
h
e
d
u
l
e
24
32
,
3
7
4
3,
5
8
3
,
3
1
3
,
0
9
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23
7
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4
1
3
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9
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4
6.
6
3
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,
4
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2
1
5
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5
7
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1
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8
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2
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6
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%
19
S
19
P
19T
24
S
24
T
1
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4
9
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6
0
5
$3
7
7
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5
2
5
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5
5
7
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4
,
0
8
3
6.
3
8
9.
6
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%
10
5
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7
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7
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6
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5
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4
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2
1
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,
5
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4
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8
5.
7
7
10
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7
1
%
3
42
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7
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4
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1
1
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6
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1
5.
0
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0
5
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,
3
4
6
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6
5
0
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5
8
11
.
0
8
%
10
9
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1
1
4
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2
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0
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0
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1
3
5
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7
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1
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8
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5
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2
1
,
9
3
6
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1
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5.
7
7
10
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7
1
%
Pr
o
p
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d
20
1
3
PC
A
Ra
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0.
0
0
6
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s
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0
1
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24
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16
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9
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1
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7
0
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,
6
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3
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4
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5
,
5
5
4
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3
7
1
7.
3
5
$9
,
8
3
3
,
4
9
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3
5
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3
8
7
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8
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9
2
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%
0
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%
16
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1
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7
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8
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3
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3
12
5
,
5
5
4
,
3
7
1
7.
3
5
$9
,
8
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4
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3
5
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3
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8
6
6
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9
2
7.
8
3
%
Po
w
e
r
Co
s
t
Ad
j
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s
t
m
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t
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m
m
a
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y
Ca
s
e
No
.
IP
C
-
E
-
1
3
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1
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a
s
e
Co
s
t
s
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e
Re
d
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s
t
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i
b
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)
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Up
(2
0
1
2
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2
0
1
3)
Re
v
e
n
u
e
fr
o
m
Fo
r
e
c
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t
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t
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a
l
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e
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f
f
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58
,
5
5
9
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5
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9
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58
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5
5
9
5
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9
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0
58
,
5
5
9
,
5
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9
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s
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r
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p
t
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j
e
c
t
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o
n
Ba
s
e
Di
f
f
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e
n
c
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or
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l
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c
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t
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d
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a
r
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d
Id
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s
t
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a
h
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t
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t
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a
l
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o
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t
to
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h
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t
h
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A
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r
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s
d
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c
t
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o
n
s
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a
r
e
h
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l
d
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r
s
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q
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m
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s
($
)
($
)
($
)
($
)
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)
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)
(!
k
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r
e
c
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s
t
or
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j
e
c
t
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o
n
(2
0
1
3
-
2
0
1
4
)
Pr
o
j
e
c
t
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o
n
I
Ba
s
e
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f
f
e
r
e
n
c
e
Ac
c
t
.
50
1
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o
a
l
16
5
,
9
5
1
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3
9
2
16
7
,
1
9
2
,
7
4
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(1
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2
4
1
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3
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Ac
c
t
.
53
6
-
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t
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r
fo
r
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w
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2,
3
5
4
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3
7
4
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8
2
8
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6
4
0
52
5
,
7
3
4
Ac
c
t
.
54
7
-
N
a
t
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r
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l
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s
66
,
5
3
6
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0
6
4
51
,
9
3
4
,
2
0
1
14
,
6
0
1
,
8
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3
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c
t
.
55
5
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Pu
r
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h
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s
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d
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(N
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n
-
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)
40
,
0
8
0
,
5
3
4
45
,
5
1
0
,
0
9
3
(5
,
4
2
9
,
5
5
9
)
Ac
c
t
.
56
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-
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n
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m
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g
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2
6
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5
6
9
,
6
1
5
)
Ac
c
t
.
44
7
-
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p
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n
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v
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8
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1
6
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(1
2
4
,
9
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6
,
1
5
3
)
26
,
4
0
5
,
9
8
4
Ac
c
t
.
44
2
-
Ho
k
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r
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k
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3
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9
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4
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23
,
9
2
1
,
4
6
6
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c
t
.
55
5
-
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r
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h
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d
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P
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)
13
1
,
7
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5
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6
62
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8
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4
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4
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,
8
8
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0
7
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m
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s
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11
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2
5
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6
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8
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3
0
5
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b
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t
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l
31
9
,
5
0
5
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0
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9
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47
4
,
4
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13
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9
0
0
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1
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4
1
6
,
5
7
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23
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8
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4
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1
21
,
5
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9
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65
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26
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23
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3
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29
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2
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4
5
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1
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9
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24
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7
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69
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,
5
8
8
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9
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,
5
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22
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27
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5
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41
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4
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5
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0
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7
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.
50
1
-
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l
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7
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0
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7
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.
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6
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r
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2
9
5
,
5
9
7
Ac
c
t
.
54
7
-
Na
t
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r
a
l
Ga
s
31
,
5
9
3
,
4
8
3
Ac
c
t
.
55
5
-
Pu
r
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a
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d
Po
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o
n
-
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56
,
0
0
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,
4
8
4
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.
56
5
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m
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CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 17TH DAY OF MAY 2013,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF,IN CASE
NO.IPC-E-13-10,BY EMAILING AND MAILING A COPY THEREOF,POSTAGE
PREPAID,TO THE FOLLOWING:
LISA D NORDSTROM TIMOTHY E TATUM
REGULATORY DOCKETS GREGORY W SAID
IDAHO POWER COMPANY IDAHO POWER COMPANY
P0 BOX 70 P0 BOX 70
BOISE ID 83707-0070 BOISE ID 83707-0070
E-MAIL:[e-mail] E-MAIL:[e-mail]
[e-mail] gsaid(),idahopower.com
PETER J RICHARDSON DR DON READING
GREGORY M ADAMS 6070 HILL ROAD
RICHARDSON &O’LEARY BOISE ID 83703
P0 BOX 7218 E-MAIL:[e-mail]
BOISE ID 83702
E-MAIL:[e-mail]
greg(richardsonando1eary.com
SECRETARY
CERTIFICATE OF SERVICE