20120515Comments.pdf

DONALD L. HOWELL, II
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
P0 BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 3366
RECEIVED
2017 MAY 15 PH 1:59
t)
tJT1j1i•S COMMSlO
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR ) CASE NO. IPC-E-12-17
AUTHORITY TO IMPLEMENT POWER )
COST ADJUSTMENT (PCA) RATES FOR )
ELECTRIC SERVICE FROM JUNE 1, 2012 ) COMMENTS OF THE
THROUGH MAY 31, 2013. ) COMMISSION STAFF
)
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
Attorney of Record, Donald L. Howell II, Deputy Attorney General, and submits the following
comments in response to Order No. 32533 issued on April 25, 2012.
BACKGROUND
Idaho Power Company filed its annual power cost adjustment (PCA) Application on
April 13, 2012 for rates to be effective June 1, 2012 through May 31, 2013. The PCA is a
symmetrical rate adjustment mechanism that annually adjusts rates to recover a portion of above
normal power supply costs from customers, or refund a portion of below normal power supply
costs to customers. Idaho Power calculates the total PCA revenue increase in this case to be
approximately $43.0 million which would result in an average rate increase of approximately
5.1%. When the proposed PCA increase is combined with the $27.1 million rate credits from the
Company's Revenue Sharing case (Case No. IPC-E-12-13), the Company calculates an overall
STAFF COMMENTS I MAY 15, 2012
average rate increase for tariff customers (i.e., non-special contract customers) of 1.71%. The
net rates are shown in the PCA Schedule No. 55. The annual PCA rate is combined with the
Company's "base rates" to produce a customer's overall billing rate.
IDAHO POWER COMPANY'S FILING
PCA Mechanism
The annual PCA mechanism is comprised of three components: 1) a "forecast" that
estimates the difference between normal power supply costs embedded in base rates and the
coming year's power supply costs; 2) a "true-up" that captures the difference between the
previous year's projection and actual power supply costs; and 3) a "reconciliation" of the
previous year's true-up to capture the unrecovered or under-refunded amount. Each component
is described in more detail below.
1.The Forecast. Forecasted power supply costs for the coming year are based on the
Company's most recent Operating Plan and measures the difference between forecasted and
normal power supply costs. The power supply cost difference is converted to a cents per
kilowatt-hour (0/kWh) rate by dividing the power costs by projected jurisdictional energy sales.
In this PCA case, the Company calculates above normal power supply costs of $70.3 million
relative to power supply costs contained in current base rates. After the 95/5 sharing, this
produces PCA rates to recover the forecasted above normal power supply costs in the amount of
0.5099 0/kWh.
2.The True-up. The true-up amount is the difference between normal and actual power
supply costs during the previous year. The previous year's PCA amount is not precisely
recovered due to actual power supply costs being different than forecasted power supply costs.
The true-up amount is also converted to a 0/kWh rate by dividing by projected jurisdictional
energy sales of 13,172,433 mWh. Idaho Power calculates the true-up amount and rate to be a
credit to ratepayers of $17,646,658 and a credit to customers of 0.1340 0/kWh, respectively.
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 reconciliation of the
true-up amount and rate to be a credit to ratepayers of $5,165,169 and 0.0392 0/kWh,
respectively.
STAFF COMMENTS 2 MAY 15, 2012
In summary, this year the PCA rate for each class is the combination of the three PCA
rate components discussed above, and a Revenue Sharing rate (discussed below). The Company
calculates the combination of the three PCA components produces a 2012/2013 PCA rate
surcharge of 0.3367 0/kWh (0.5099 - 0.1340 - 0.0392).
Revenue Sharing
The Idaho Power Revenue Sharing case (Case No. IPC-E-12-13) is being processed
concurrently with this PCA case. In the Revenue Sharing case the Company proposes to credit
$27.1 million to Idaho customers. The Company proposes that the Revenue Sharing credit be
used to offset the proposed PCA increase. Idaho Power proposes that the Revenue Sharing credit
be spread to customer classes on a uniform percent of base revenue basis and applied to reduced
energy rates. These energy credits differ for each customer class. This results in a different
PCA/Revenue Sharing energy rate for each customer class. These proposed rates are shown on
Company Exhibit No. 2. For the four special contract customers, Idaho Power proposes that they
each receive a different, flat-monthly credit during the PCA year. The proposed credits are:
Micron - $46,803/mo.; Simplot - $18,362/mo.; DOE - $22,906/mo.; and Hoku - $7,685/mo.
Atach 2, p.3. These rates are included in Tariff Schedule No. 55 which would be effective
June 1, 2012 and would remain in effect for one year.
STAFF AUDIT AND ANALYSIS
A. The PCA Forecast or Projection
The Operating Plan used to forecast power supply costs is based on the most current
information available to the Company. It takes many factors into consideration such as water
conditions, gas hedges, market purchases, transmission availability, the cost of PURPA
contracts, etc. 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 shared. The entire difference in PURPA QF contracts is passed on to
customers.
STAFF COMMENTS 3 MAY 15, 2012
Attachment B shows Staff s 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 0.0005 0/kWh.
Lines 10 through 12 show the calculation of the second element of the forecast rate
component. 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 0.4830 0/kWh as shown on line
12. This is by far the largest part of this year's PCA rate increase.
The third forecast rate element is new this year. It is Demand Response Incentives and
the calculations are shown on lines 14 through 16. Commission Order No. 32426 allows Idaho
Power to capture the difference between base and actual Demand Response Payments in the
PCA. This third PCA forecast element is shown on line 16 to be 0.0264 0/kWh. These three
elements combine to produce the PCA forecast rate component of 0.50990/kWh shown on line
18. This rate is almost entirely composed of expected increases in PURPA contract expenses.
The Staff agrees with the Company's forecast calculations.
B. The PCA True-Up
The PCA true-up difference is netted against the amount collected from the application of
the previous year's true up rates. This difference represents the PCA true-up deferral balance.
This deferral balance is divided by expected kWh jurisdictional sales to provide the true-up rate
component.
Page 1, lines 4 through 90 of Company Exhibit No. 1 calculates a true-up deferral amount
a credit of $17,646,658. Attachment C contains Staff's verification of the Company's true-up
deferral calculations. Staff finds the Company's calculation as shown in Exhibit No. 1 to be
correct.
To verify revenues and costs associated with Idaho Power's true-up deferrals, Staff
conducted an audit of actual revenues and expenses that occurred during the PCA year
(April 1, 2011 through March 30, 2012). 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, Hoku First Block Energy revenues, Renewable Energy Credits
STAFF COMMENTS 4 MAY 15, 2012
(RECs) sales, Emission Allowance sales, and Qualifying Facilities (QF) expenses. The Risk
Management Operating Plans and RMC minutes were also reviewed.
The following items are included in the PCA true-up component:
1.Load Change Adjustment. This year's true-up calculation includes a negative Load
Change Adjustment of $12,621,398. Actual loads during the true-up year were below normal
loads in 11 of 12 months. The actual load for the PCA year was below normal by 655,506
MWh. This represents a 4.2% decline in load. The load change adjustment is the product of the
negative load growth and the load change adjustment rate (LCAR) of $1 9.67/MWh for the
months of April through December 2011, and $18.1 6/MWh for January through March 2012.
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 $12,621,398 (before Jurisdictional Allocation and
PCA sharing) has been added to the deferral balance for recovery from customers in this year's
PCA. This increase due to the LCAR is a cost to customers and is subject to jurisdictional
allocation and sharing.
2.Water Leases. The Company sometimes leases water for the production of hydro
power from several entities. 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 $2,577,915 and the amount included in base rates
is $1,825,371, with the difference of $752,544 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. A portion of Idaho Power's electricity comes from coal plants.
The three coal plants that Idaho Power owns an interest in are the Bridger, Valmy and Boardman
plants. 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 audit period of April 2011 to March 2012, the total
coal expense for the three plants is $122,922,864. The total coal expense included in base rates
is $167,418,061. This year's PCA deferral balance includes a difference between costs currently
included in rates and actual costs of $44,495,197. This decrease in coal costs from base costs is
a benefit to customers and is subject to jurisdictional allocation and sharing.
STAFF COMMENTS 5 MAY 15, 2012
4. Fuel Expense - Gas. Idaho Power currently owns and operates several gas-fired
combustion turbine generating plants at the Evander Andrews Power Complex (3 Danskin units)
and at Bennett Mountain. These plants are located at Mountain Home and currently account for
100% of the Company's natural gas usage.
For the audit period of April 2011 through March 2012, the total variable gas and gas
transportation expense for all the gas plants was $10,877,122. The total gas and gas
transportation expense included in base rates is $6,051,627. This increase in gas expense from
base rates is included in the PCA. In this year's PCA deferral balance, the additional gas expense
that is included for future recovery from customers is $4,825,495. This increase in natural gas
expenses from base expenses is a cost to customers and is subject to jurisdictional allocation and
sharing.
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 not
reasonable or did not follow the Risk Management Committee's recommendations. These
transactions were made with an assortment of credit-worthy partners on a timely basis, and there
were no transactions conducted with an Idaho Power affiliate.
a.Power Sales. During the PCA year ending March 31, 2012, the Company sold off-
system surplus power totaling $96,750,895. The total surplus sales included in base rates is
$92,476,391. This increase in the power sales from base rates is included in the PCA. Actual
surplus sales were more than base amounts by $4,274,504. This increase in revenues is a benefit
to customers and is subject to jurisdictional allocation and sharing.
b.Power Purchases. During the PCA year ending March 31, 2012, the Company
made market power purchases, excluding its PURPA contracts. The total amount of power
purchases is $62,156,365. The amount of power purchases included in base rates is $66,570,302.
Actual power purchases were less than base amounts by $4,413,937. This decrease in costs is a
benefit 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.
STAFF COMMENTS 6 MAY 15, 2012
For the audit period of April 2011 through March 2012, the actual third-party
transmission expense is $6,516,274. The third-party transmission expense included in base rates
is $8,247,222. This year's PCA deferral balance includes the difference between actual costs and
base costs of $1,730,948. 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-1 1-08), 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 are tracked in the PCA. The amount of Hoku First Block Energy revenues
included in base rates is $5,773,675. The actual amount of Hoku First Block Energy revenues
during the current PCA period is $14,477,351. The actual revenues are more than the amount
included in base rates by $8,703,676. These additional revenues are a benefit to customers and
are 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. The amount included in the deferral balance is $25,202
and is a benefit to customers.
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 $5,521,597
and is a benefit to customers.
10.Actual PURPA Purchases Including Net Metering and Raft River Expenses. A
Qualifying Facility (QF) is a generating facility which meets the requirements for QF status
under the Public Utility Regulatory Policies Act of 1978 (PURPA) and FERC's 18 C.F.R. Part
292, and has obtained certification of its QF status.
For the audit period of April 2011 through March 2012, the actual PURPA expense is
$103,846,995. The PURPA expense included in base rates is $62,739,020. 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 was
more than the PURPA expense included in base rates by $41,107,975. This amount is a cost to
STAFF COMMENTS 7 MAY 15, 2012
customers and increases the PCA deferral balance. PURPA contracts are not currently subject to
sharing, but they are subject to jurisdictional allocation.
11. Demand Response Incentive Payments. In Order No. 32426 (Case No. IPC-E-1 1-
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), there were no actual Demand
Response Incentive Payments. The base amount of incentive payments included in base rates
during the PCA period is $2,715,842. The difference between the actual amount and the base
amount is $2,715,842 and is a benefit to customers.
The Idaho customer true-up Deferral Balance is composed of the following:
Load Change Adjustment $12,621,398
Water Leases $752,544
Fuel Expense Coal $(44,495,197)
Fuel Expense - Gas $4,825,495
Surplus Sales $(4,274,504)
Non-Firm Purchases $(4,413,937)
Third Party Transmission $(1,730,948)
Hoku Energy $(8,703.676)
Subtotal - Change from Base $(45,418,825)
Emission Allowance Sales Credit $(25,202)
Renewable Energy Credit Sales $(5,521,5971
Subtotal - Subject to Jurisdictional Allocation & Sharing $(50,965,624)
Subtotal - After Jurisdictional Allocation and Sharing $(45,996,476)
Qualifying Facilities - After Jurisdictional Allocation $39,052,576
Demand Response Incentive Payments $(2,715,842)
Total all Expense Items $(9,659,742)
Revenue from the Forecast $(7,823,682)
Deferral Balance $(17,483,424)
Interest on the Deferral Balance $(163,234)
Deferral Balance (Credit) $(17,646,658)
The Company-proposed true-up rate credit is 0.1340 0/kWh. Although Staff calculates
the same rate, as shown on Staff Attachment B, line 23, Staff is concerned that the Company
does not use actual energy sales to calculate revenue from the previous year's forecast rate. The
Company uses normalized energy amounts. The methodology used by the Company has been in
use for many years and has been accepted by the Commission as it has approved past PCA rates.
STAFF COMMENTS 8 MAY 15, 2012
Instead of using normalized energy sales to estimate forecast revenues in determining true-up
revenue, Staff believes it may be more appropriate in future PCA years for the Company to use
actual energy sales and the approved forecast rate to determine true-up revenue. Staff proposes
to immediately initiate discussions with the Company to resolve the issue on a prospective basis.
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 may benefit either the Company or
customers because any true-up over-collection is returned to customers, and any true-up under-
collection is recovered by the Company.
The reconciliation of the true-up included the following amounts:
2010-11 Forecast True-Up $ 4,181,114
2010-11 True-Up of the True-Up Balance ($18,152,666)
Emission Allowance (Order No. 32250) ($ 491,989)
DSM Recovery (Order No. 32217) $ 10,000,000
Net Amount Set for Recovery/(Refund) ($ 4,463,541)
Collection from True-Up Rates ($ 634,702)
Interest ($ 66,926)
True-Up Reconciliation (Credit) ($ 5,165,169)
This is the amount recommended for refund by the Company and Staff. When divided by
expected sales it produces the reconciliation of the true-up rate credit 0.0392 0/kWh. This
calculation is shown on Attachment B, line 25.
D.Revenue Sharing
Because the Company proposes to offset the proposed increase in PCA rates with
Revenue Sharing credits, Staff reviewed Idaho Power's class allocation of the Revenue Sharing
amount. 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. Within
each customer class the decrease was assigned to the energy rates. This creates a different
0/kWh rate for each class. Staff accepts this revenue allocation and rate design.
The reconciliation of the true-up is also commonly referred to as the "true-up of the true-up."
STAFF COMMENTS 9 MAY 15, 2012
PCA AND REVENUE SHARING RATES
The uniform PCA rate surcharge of 0.3367 0/kWh is the sum of the three PCA
components described above (0.5099 - 0.1340 - 0.0392). This new PCA surcharge rate, shown
on Attachment B, line 28, replaces the 0.0629 0/kWh credit currently contained within Schedule
55 rates. In this case, the uniform PCA rate is combined with Revenue Sharing credits to arrive
at the total PCA rate for each class. Attachment D shows these rates.
Combined PCA and Revenue Sharing Recovery
Attachment E shows the percentage increase in the Combined PCA-Revenue Sharing
rates for all Idaho Power customer classes. It includes the uniform PCA increase and the
Revenue Sharing decrease. The impact is measured against all billed revenue. The total Staff-
recommended increase is $15.9 million which represents an average revenue increase of 1.89%
Increase or decrease percentages vary by customer class. Staff agrees with the Company's
proposed combined rates in Schedule 55.
Other PCA Attachments
Staff has included two other attachments that provide summary or historical information
concerning the PCA. Staff Attachment F 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 G is a bar graph that shows the amount of
each PCA since its inception.
CUSTOMER NOTICE AND PRESS RELEASE
Idaho Power's PCA Application, filed on April 13, 2012, contained both the Customer
Notice and Press Release. Staff reviewed both and determined they complied with requirements
of Procedural Rule 125.01, IDAPA 31.01.01.125.01. However, the Customer Notice does not
comply with requirements of Procedural Rule 125.03, IDAPA 31.01.01.125.03.
Rule 125.03 requires that the information provided in Customer Notices should be
"clearly identified, easily understood, and pertain only to the proposed rate change." In the
notice sent in this case, five paragraphs are devoted to discussing Public Utility Regulatory
Policy Act (PURPA) costs. Although Staff recognizes that PURPA expenses are a major cost
component in this year's PCA filing, Idaho Power's discussion of PURPA strays into a
STAFF COMMENTS 10 MAY 15, 2012
discussion of expected future PURPA costs and how those future costs will impact customers in
another generic case. Although the case number for the instant PCA case (IPC-E- 12-17) is not
mentioned in the notice, the case number for the generic PURPA case (GNR-E- 11-03) is given.
The Customer Notice states that the Commission is accepting public comment in GNR-E-11-03,
but there is no statement to that effect with respect to this PCA case.
In the first paragraph under the section labeled "How PURPA Impacts the PCA", the
Company compares this year's PURPA-related power supply expenses to those same expenses in
2004. Staff believes a more appropriate comparison between PURPA expenses would be to
compare the current PCA case and last year's PCA case. Rule 125.01 requires that the Customer
Notice give the overall percentage change from current rates. As one customer noted in his
comment, "It seems that Idaho Power is waging an all out war against PURPA projects." In
Staff's opinion, the Customer Notice violates Rule 125.03 by addressing and referring to issues
that are currently the subject of a different case. At a minimum, the invitation for customers to
comment in a separate and distinct case is confusing and misleading.
Another issue of concern is the delay in mailing Notices to customers. Although the
Application was filed with the Commission on April 13, the Customer Notice was mailed with
Idaho Power's cyclical billings beginning on April 26, 2012 and ending May 24, 2012. Pursuant
to the Commission's Notice of Application, customers had until May 15, 2012 to file comments
regarding this case. The delay is problematic, particularly in a PCA case that typically has a
much shorter timeline than that of general rate cases. More than 100,000 customers would not
have received the Customer Notice in their bills until the comment deadline passed.
In response to this concern about the delayed notice, the Company notified Staff on
May 4, 2012, that it would issue a "supplemental" Customer Notice in the form of a post card to
most of the customers who would not have receive the original Notice in their bills before the
comment deadline of May 15, 2012. The affected customers will receive the supplemental
Notice via direct mail by May 17, 2012, and will also receive the original Notice in their monthly
bills. Staff agrees with the Company that this will provide affected customers with "the
opportunity.. .to submit comments in this case prior to a Commission decision", although the
turn-around time for some customers will be quite short. For this reason, Staff encourages the
Commission to consider late-filed comments from customers in its deliberations.
STAFF COMMENTS 11 MAY 15, 2012
The Company indicated to Staff that there were two reasons for the delay in sending the
Customer Notice in this case. First, the Company did not want to include more than one
Customer Notice in bills; bills including the Notice regarding Case Nos. IPC-E-12-12,
IPC-E-12-13 and IPC-E-12-14 were being mailed until April 23, 2012. Second, the Company
reports that it takes ten days for the Customer Notices to be printed locally and then shipped to
the billing vendor (located in California) that prints, stuffs, and mails the bills. In discussions
with Staff, Idaho Power has acknowledged that the processing delay is problematic. The
Company is now exploring options on how it can decrease the time it takes to provide customer
notification, particularly with respect to cases with abbreviated comment periods such as this
one.
Staff recommends that the Company be reminded of its obligation to provide timely
notice to customers and be directed to comply with Procedural Rule 125 in future cases.
STAFF RECOMMENDATION
Staff recommends that the Commission approve the Company's Application and the
combined PCAlRevenue Sharing rates filed by the Company in proposed Schedule 55.
Staff recommends that the Commission approve a total PCA rate comprised of the
uniform 0/kWh increase of 0.3367 and class-specific rates, as shown on Attachment D, to credit
customers for Revenue Sharing amounts. The Staff recommends that these rates be effective
June 1, 2012 through May 31, 2013.
Staff recommends that the Company be reminded of its obligation to provide timely
notice to customers and be directed to comply with Procedural Rule 125 in future cases.
Respectfully submitted this it day of May 2ol2.
Donald L. IfoUll, 11
Deputy Attorney General
Technical Staff: Keith Hessing
Kathy Stockton
Matt Elam
Marilyn Parker
I :umisc:comments/ipce 12.1 7dhldskhmemp comments
STAFF COMMENTS 12 MAY 15, 2012
C
0
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C w 0. X w
>1
0.
0.
w
0
0.
200
150
100
50
0
(50)
300
250
(100)
POWER SUPPLY COST PROJECTION
2012 - 2013 PCA Year
• Base Cost
• Forecast Cost
• Difference
Coal Ex e Water For Natural Gas Non-P PURPA Transmission S su First Demand Total
Power Expense Purch Purchases Expense ue lock Response
Revenue
0 (150) p
rrj
im
11,252,265
(17,646,658)
(5,165,169)
14,723,210
(MWh)
13,172,433
13,172,433
Rate
0.0005
0.4830
0.0264
0.5099
(/kWh)
(0.1340)
(0.0392)
0.3367 I
(0.0629)
0.3996
Base Forecast

133,997,217 140,832,145
(6,765,150)
134,066,995

62,851,454 129,590,113
Difference
69,778
0.95
66,289
13,816,139
0.0005
66,738,659
13,816,139
0.4830
3,470,945
13,172,433
0.0264
($/MWh)
-1.340
-0.3921
2012-2013 PCA - Twentieth Annual
IPC-E-1 2-17
Staff Case
(a) (b) (c) (d) (e) (f) (g)
Line Description Units
1 Forecast 2012-2013:
2 PCA Expense (95%) ($)
3 Hoku First Block Revenue ($)
4 Difference ($)
5 Sharing Percentage (%)
6 Shared Difference ($)
7 Normalized System Firm Sales (MWH)
8 Rate for 95 % Items (/kWh)
9
10 PCA Expense (100%) ($)
11 Normalized System Firm Sales (MWH)
12 Rate for 100% Items (/kWh)
13
14 Demand Response Incentives (100%) ($)
15 Idaho Jurisdictional Sales (MWH)
16 (0/kWh)
17
18 Total Forecast Rate (/kWh)
19
20
21
22
23 True-Up of 2011-2012:
24
25 True-Up of the True-Up:
26
27 PCA Rates:
28 PCA Rate Adjustment From Base (/kWh)
29 PCA Rate Currently in Effect (/kWh)
30 Difference - Last Year to This Year (/kWh)
31
32 Note: Negative rates and amounts indicate benefits to ratepayers.
33 The True-Up calculation includes 95% sharing
CD
TRUE-UP CALCULATIONS FOR 2011 -2012
FOR
IDAHO POWER COMPANY PCA
CASE NO. IPC-E-12-17
(Base Costs are Redistributed)
1 2011 2011 2011 2011 2011 2011 2011
2 DESCRIPTION Units APR MAY JUN JUL AUG SEPT OCT
3 PCA Revenue
4 Normalized Idaho Jurisd. Sales MWh 955,398 960,840 1,115,486 1,354,071 1,414,294 1,295,747 1,035,451
5 Forecast Rate $/MWh 1.404 1.404 0.445 0.445 0.445 0.445 0.445
6 Revenue $ 1,341,379 1,349.019 496,391 602,562 629,361 576,607 460,776
7
8 Load Change Adjustment
9 Actual System Firm Load - Adjusted MWh 1,011,234 1,097,667 1,300.475 1,685,331 1.585,233 1,293,353 1,040.237
10 Normalized Firm Load MWh 1,085,384 1,282,341 1,412,842 1,685,870 1.594.331 1,225,589 1,100,776
11 Load Change MWh (74,150) (184,674) (112,367) (539) . (9,098) 67,764 (60,539)
12 Expense Adjustment $ 1,458,531 3,632,538 2,210,259 10,602 178,958 (1,332,918) 1,190,802
14 Non-QF PCA
IS ACTUAL:
16 Water Leases $ 0 (514,305) 0 0 1,464,305 1,542,915 0
17 Fuel Expense - Coal $ 6,666,551 4,771,128 5,801,423 10,194,091 13,870,557 11,740.380 11.160,165
18 Fuel Expense - Gas $ 456,072 479,664 1,392.041 1,577,118 3,177,032 485,041 491,516
19 Non-Firm Purchases $ (264,797) 1,509,941 8,112,353 14,768,259 15,265,932 4,739,731 2,401,316
20 Third Party Transmission $ 337,992 309,423 1,054,471 898,300 860.272 519,502 883,914
21 Surplus Sales $ (6,221,929) (6,211,722) (7,210,510) (4,788,485) (7,930,627) (10,016,187) (11.818.634)
22 Hoku First Block Energy $ 0 (1,638,183) (1,692,789) (1,178,693) (743.176) (2,561,825) (1,692.789)
23 Expense Adjustment $ 1,458,531 3.632,538 2,210,259 10,602 178,958 (1,332,918) 1,190,802
24 Sub-Total $ 2.432.419 2,338,483 9,667,248 21,481,193 26,143,252 5,116,640 2,616,289
25
26 BASE:
27 Water for Power (Leases) $ 125,711 124,705 153,090 190,953 204,643 179,325 133,942
28 Fuel Expense - Coal $ 11,529,868 11,437,623 14,041,049 17,513,694 18,769,296 16,447,224 12,284,817
29 Fuel Expense - Gas $ 416,768 413,433 507.539 633,064 678,450 594,515 444.057
30 Non-Firm Purchases $ 4,584,612 4,547.932 5,583,131 6,963,955 7,463,219 6.539,896 4.884.802
31 Third Party Transmission $ 567,976 563,431 691,679 862.746 924,599 810,211 605.165
32 Hoku First Block Energy $ 0 0 0 0 0 0 0
33 Surplus Sales $ (6,368,731) (6,317,778) (7,755,827) (9,674.005) (10,367,560) (9,084.921) (6,785,741)
34 Sub-Total $ 10.856,204 10,769.346 13.220,661 16,490,407 17,672,647 15,486,250 11,567,042
35
36 Change From Base $ (8,423.785) (8.430,863) (3,553.413) 4,990,786 8,470,605 (10,369,610) (8.950,753)
37 Emission Allowance Sales Credit $ 0 0 0 (21,756) 0 0 0
38 Renewable Energy Credit Sales $ (998,372) (307,898) (264.172) (623,014) (550,822) (410,643) (403,702)
39 Sub-Total $ (9,422,167) (8,738,761) (3,817,585) 4,346,015 7,919,782 (10.780,253) (9,354,455)
40
41 Deferral (Shared and Allocated) $ (8,503,496) (7,886,732) (3,445,370) 3,922,279 7.147,603 (9,729.178) (8,442,396)
42
43 Demand Response Incentive Pmts.
44 Actual $ 0 0 0 0 0 0 0
45 Base $ 0 0 0 0 0 0 0
46 Change From Base $ 0 0 0 0 0 0 0
47 Deferral $ 0 0 0 0 0 0 0
49 OF Deferral
50 Actual (includes Net Metering) $ 6.235.518 8,098,202 11.029,872 11,225,589 9,677,446 8.186,389 7,619,052
51 Base $ 4,320,756 4,286,188 5,261,808 6,563,163 7,033.693 6,163,509 4.603,670
52 Change From Base $ 1,914,762 3,812,014 5,768,064 4.662,426 2,643,753 2,022.880 3,015.382
53 Deferral (Allocated) $ 1,819,024 3,621,413 5,479,661 4,429,305 2,511.565 1,921,736 2,864,613
54
55 Total Deferral (-6+41+47+53) $ (8,025,851) (5,614,338) 1,537,899 7,749,022 9.029.808 (8,384,049) (6,038,558)
56
57 Principal Balances
58 Beginning Balance $ 0 (8,025,851) (13.640,189) (12,102,290) (4,353,268) 4.676,540 (3,707,509)
59 Amount Deferred $ (8,025,851) (5,614,338) 1,537,899 7,749.022 9,029,808 (8,384,049) (6,038,558)
60 Ending Balance $ (8,025.851) (13,640.189) (12,102,290) (4,353,268) 4,676,540 (3,707,509) (9.746,067)
61
62 Interest Balances
63 Accrual thni Prior Month $ 0 (7) 1,476 3,044 3,648 (5,786) (21,278)
64 Interest@ 1% per Year $ 0 1,483 1.569 603 (9,432) (15.492) (23,018)
65 Prior Month's Interest Adj. $ (7) 0 0 0 (1) (0) (0)
66 Total Current Month Interest $ (7) 1,483 1,569 603 (9,434) (15.492) (23,018)
67 Interest Accrued to Date $ (7) 1,476 3,044 3,648 (5.786) (21 .278) (44,296)
68 Balance (True-Up & Interest) $ (8,025,858) (13,638,713) (12,099,245) (4.349,620) 4,670,754 (3,728,787) (9,790,363)
69
70 True-Up of the True-Up
71 True-Up Revenues (Collections) $ 1,601,969 1,526,938 978,989 (420,058) (479,166) (458,114) (381,700)
72
73 Beginning Balance $ (18,152,666) (5,576,831) (7,600,815) (8,586,138) (8,173,235) (7,700,880) (7,249,183)
74 Adjustments:
75 2009-loPCATransfer $ 4,181,114 0 0 0 0 0 0
76 Emission Allowance - ON 32250 $ 0 (491.989) 0 0 0 0
77 Rider Funds - O.N. 32217 $ 10,000,000 0 0 0 0 0
78 Sub-Total $ (3,971,552) (6,068,820) (7.600,815) (8,586,138) (8,173.235) (7,700,880) (7,249,183)
79 lnterestt 1% per Year $ (3,310) (5,057) (6,334) (7.155) (6,811) (6,417) (6,041)
80 Revenue Applied to Interest $ (3,310) (5,057) (6,334) (7,155) (6,811) (6,417) (6,041)
81 Revenue Applied to Balance $ 1,605,278 1,531.996 985,323 (412,903) (472,355) (451,697) (375,659)
82 True-Up of the True-Up Balance $ (5,576,831) (7,600,815) (8,586,138) (8,173,235) (7.700,880) (7,249,183) (6,873,525)
Note: Negative amounts indicate benefit to ratepayers Attachment C -
Case No. IPC-E12-17
Staff Comments
05115112 Page 1 of 2
TRUE-UP CALCULATIONS FOR 2011 -2012
FOR
IDAHO POWER COMPANY PCA
CASE NO. IPC-E-12-17
(Base Costs are Redistributed)
2011 2011 2012 2012 2012
2 DESCRIPTION Units NOV DEC JAN FEB MAR TOTALS
3 PCA Revenue
4 Normalized Idaho Jurisd. Sales MWh 956,566 1,061,014 1,177,663 1,101,149 1,004,028 13,451,707
5 Forecast Rate $/MWh 0.445 0.445 0.445 0.445 0.445
6 Revenue $ 425,672 481,051 524,060 490,011 446,792 7,823,682
7
8 Load Change Adjustment
9 Actual System Firm Load - Adjusted MWIi 1,124,273 1,285,108 1,248,576 1,110,751 1,080,667 14.862,905
10 Normalized Firm Load MWh 1.130.765 1,380,118 1,346,312 1,139,208 1,134,875 15,518,411
11 Load Change MWh (6,492) (95,010) (97,736) (28,457) (54.208) (655,506)
12 Expense Adjustment $ 127,698 1868,847 1,774,886 516,779 984,417 12,621,398
13
14 Non-OF PCA
15 ACTUAL:
16 Water Leases $ 0 0 0 0 85,000 2,577.915
17 Fuel Expense - Coal $ 12,465,839 15,168,660 12,745,738 10,750,313 7.588,020 122,922,864
18 Fuel Expense - Gas $ 432,515 868,953 443,209 512,867 561,096 10,877,122
19 Non-Firm Purchases $ 3,340,059 3,783,652 3,745,779 2,106,087 2,648,054 62,156,365
20 Third Party Transmission $ 291,183 443,772 308,159 289,909 319,378 6,516,274
21 Surplus Sales $ (7,165,338) (7,744,097) (8,165,168) (8,830,414) (10,647,785) (96,750,895)
22 Hoku First Block Energy $ (1,640,458) (1,692,789) (545,550) (545,550) (545,550) (14,477,351)
23 Expense Adjustment $ 127.698 1,868,847 1,774,886 516,779 984,417 12,621.398
24 Sub-Total $ 7,851,498 12,696,998 10,307,052 4,799,991 992,630 106,443.691
25
26 BASE:
27 Water for Power (Leases) $ 125,889 145,752 160,651 147,407 133,303 1,825,371
28 Fuel Expense - Coal $ 11,546,178 13,367,949 14,734,456 13,519,751 12,226,156 167,418,061
29 Fuel Expense - Gas $ 417,357 483,209 532,603 488,696 441,936 6,051 .627
30 Non-Firm Purchases $ 4,591,097 5,315,486 5,858,849 5,375,847 4,861,476 66,570,302
31 Third Party Transmission $ 568,779 658,522 725,838 666.000 602,276 8,247,222
32 Hoku First Block Energy $ 0 0 (2.101,561) (1,928,309) (1,743,805) (5,773,675)
33 Surplus Sales $ (6,377,740) (7,384,028) (8,138,843) (7,467,879) (6,753,338) (92,476,391)
34 Sub-Total $ 10,871,560 12,586.890 11,771,993 10,801,513 9,768,004 151,862,517
35
36 Change From Base $ (3,020,062) 110,108 (1,464,941) (6,001,522) (8,775,375) (45,418,826)
37 Emission Allowance Sales Credit $ 0 0 (3,446) 0 0 (25,202)
38 RenewableEnergyCredit Sales $ (688,711) (384.236) (326,785) (280,351) (282,891) (5,521,597)
39 Sub-Total (3,708,773) (274,128) (1.795.171) (6,281,873) (9,058,266) (50,965,625)
40
41 Deferral (Shared and Allocated) $ (3,347,167) (247,401) (1.620,142) (5.669.391) (8,175,085) (45.996,477)
42
43 Demand Response Incentive Pmts.
44 Actual $ 0 0 0 0 0 0
45 Base $ 0 0 988.540 907,045 820,257 2.715,842
46 Change From Base $ 0 0 (988,540) (907,045) (820.257) (2,715,842)
47 Deferral $ 0 0 (988,540) (907,045) (820.257) (2,715,842)
48
49 QF Deferral
50 Actual (includes Net Metering) $ 9,540,246 7,374,112 9,614,927 8,156,684 7,088,958 103,846,995
51 Base $ 4,326,868 5,009,567 5,521,658 5,066.454 4,581.686 62.739,020
52 Change From Base $ 5,213,378 2,364,545 4,093,269 3,090,230 2,507,272 41,107,975
53 Deferral (Allocated) $ 4,952,709 2,246,318 3,888,605 2,935.718 2,381,908 39,052,576
54
55 Total Deferral (-6+41+47+53) $ 1,179,870 1,517,866 755,863 (4,130,729) (7.060,226) (17,483,424)
56
57 Principal Balances
58 Beginning Balance $ (9,746,067) (8,566,198) (7,048,332) (6,292.469) (10,423,198)
59 Amount Deferred $ 1,179,870 1.517,866 755.863 (4,130.729) (7,060,226) (17,483,424)
60 Ending Balance $ (8.566,198) (7,048,332) (6,292,469) (10,423.198) (17,483,424)
61
62 Interest Balances
63 Accrual thru Prior Month (44,296) (70.608) (97,900) (125,294) (147,241)
64 Interest@ 1% per Year (26,312) (27,299) (27,394) (21,947) (15,993) (163,232)
65 Prior Month'sInterest Adj. $ 0 6 0 0 0 (3)
66 Total Current Month Interest (26,312) (27,292) (27.394) (21,947) (15,993) (163.234)
67 Interest Accrued to Date (70,608) (97,900) (125,294) (147.241) (163,234)
68 Balance(True-Up&Interest) (8,636,806) (7,146.232) (6,417.764) (10,570,439) (17,646,658) (17,646,658)
69
70 True-Up of the True-Up
71 True-Up Revenues (Collections) $ (330,805) (352,881) (363,912) (352,417) (334,141) 634,702
72
73 Beginning Balance $ (6,873,525) (6,548,448) (6,201,024) (5,842,279) (5,494,731) (18,152,666)
74 Adjustments:
75 2009-lOPCATransfer $ 0 0 0 0 0 4,181,114
76 Emission Allowance - ON 32250 0 0 0 0 0 (491,989)
77 Rider Funds - O.N. 32217 0 0 0 0 0 10,000.000
78 Sub-Total (6,873,525) (6,548,448) (6.201,024) (5,842,279) (5,494,731) (4,463,541)
79 Interest @ 1% per Year (5,728) (5,457) (5,168) (4,869) (4,579)
80 Revenue Applied to Interest (5,728) (5,457) (5,168) (4,869) (4,579) (66.926)
81 Revenue Applied to Balance (325,077) (347,424) (358,744) (347,549) (329,562) 701,628
82 True-Upof the True-Up Balance (6,548,448) (6,201,024) (5,842,279) (5,494,731) (5,165,169) (5,165,169)
Note: Negative amounts indicate benefit to ratepayers Attachment C
Case No. IPC-E-12-17
Staff Comments
05/15/12 Page 2 of 2
Idaho Power Company
Calculation of PCA Rate by Class
State of Idaho
Case No. IPC-E-12-17
Staff Proposal
(1) (2) (3) (4) (5) (6)
Rate Current Allocated
Line Schedule Billed Revenue Test Year Revenue Sharing Rate Uniform PCA Rate Total Combined PCA Rate
No No Revenue Sharing Benefit Billed kWh Cents per kWh Cents per kWh Cents per kWh
1 Residential Service 1,4,5 $397,700,569 ($12,600.731) 4.896.272,827 (0.2574) 0.3367 0.0793
2 Master Metered Mobile Home Park 3 $381,220 ($12,062) 4,942,681 (0.2440) 0.3367 0.0927
3 Small General Service 7 $14,990,300 ($474,246) 144,888,296 (0.3273) 0.3367 0.0094
4 Large General Service - Secondary 9S $176,38,854 ($5,732,224) 3,056,964,925 (0.1875) 0.3367 0.1492
5 Large General Service- Primary 91, $20,237,805 ($659,119) 420.423.939 (0.1568) 0.3367 0.1799
6 Large General Service - Transmission 91 $130,585 ($4,253) 2.712.595 (0.1568) 0.3367 0.1799
7 Dusk to Dawn Lighting 15 $1,173,934 ($37,871) 6,481,376 (0.5843) 0.3367 (0.2476)
8 Large Power Service - Secondary 19S $319,273 ($10,399) 6.678.959 (0.1557) 0.3367 0.1810
9 Large Power Service - Primary 19P $81,670,938 ($2,664,599) 1.930,039.445 (0.1381) 0.3367 0.1986
10 Large Power Service - Transmission 191 $1,670,079 ($54,541) 41.905,243 (0.1302) 0.3367 0.2065
11 Agricultural Irrigation Service 24 $109,78,557 ($3.563.932) 1.720,204.410 (0.2072) 0.3367 0.1295
12 Urimetered General Service 40 $1,096,24 ($35,561) 15,807,753 (0.2250) 0.3367 0.1117
13 Street Lighting 41 $2,959,897 ($95,628) 23.165,568 (0.4128) 0.3367 (0.0761)
14 Traffic Control Lighting 42 $142,887 ($4.654) 2.981.282 (0.1561) 0.3367 0.1806
15 Total Uniform Tariffs $808,645,142 ($25,949,819) 12.273.469,299
16 Special Contracts:
17 Micron 26 $17,176,418 ($561,642) 451,138,622 N/A 0.3367 0.3367
18 J RSimplot 29 $6,727,934 ($220,347) 20,558.197 N/A 0.3367 0.3367
19 DOE 30 $8,393,976 ($274,869) 244.266,665 N/A 0.3367 0.3367
20 Hoku 32 $2,835,760 ($92,221) Q N/A 0.3367 0.3367
21 Total Special Contracts $35,134,087 ($1,149,078) 898,963,484
22 Total Idaho Jurisdiction $843,779,229 ($27,098,897) 13,172,432.783
0
Combined Effect of All Filings
Staff Proposal
Present Billed Rates to 6/1/2012 Billed Rates (PCA & Revenue Sharing)
th
a
tr1
(1) (2) (3) (4) (5) (6) (7) (8)
Rate Average Normalized Current Billed Proposed
Sch. Number of Energy Billed Revenue Billed Average Percent
No. Customers (kWh) Revenue Adiustments Revenue c/kWh Change
1 399,329 4,896,272,827 $397,700,569 $ 2,469,997 $400,170,566 8.173 0.62%
3 23 4,942,681 $381,220 $ 3,152 $384,372 7.777 0.83%
4 0 0 $0 $0 $0 0 N/A
5 0 0 $0 $0 $0 0 N/A
7 28,165 144,888,296 $14,990,300 $ (64,502) $14,925,798 10.302 -0.43%
9 31,614 3,480,101,459 $196,754,244 $ 5,229,661 $201,983,905 5.804 2.66%
15 0 6,481,376 $1,173,934 $ (25,478) $1,148,456 17.719 -2.17%
19 116 1,978,623,647 $83,660,290 $ 4,204,442 $87,864,732 4.441 5.03%
24 16,642 1,720,204,410 $109,785,557 $ 2,031,893 $111,817,450 6.500 1.85%
40 2,030 15,807,753 $1,096,245 $ 14,898 $1,111,143 7.029 1.36%
41 361 23,165,568 $2,959,897 $ (37,019) $2,922,878 12.617 -1.25%
42 397 2,981,282 $142,887 $ 5,599 $148486 4.981 3.92%
478,677 12,273,469,299 $808,645,142 $ 13,832,644 $822,477,786 6.701 1.71%
26 1 451,138,622 $17,176,418 $ 1,051,179 $18,227,597 4.040 6.12%
29 1 203,558,197 $6,727,934 $ 512,666 $7,240,600 3.557 7.62%
30 1 244,266,665 $8,393,976 $ 605,712 $8,999,688 3.684 7.22%
32 1 0 $2,835,760 $ (92,221) $2,743,539 0.000 -3.25%
4 898,963,484 $35,134,087 $ 2,077,337 $37,211,424 4.139 5.91%
478,681 13,172,432,783 $843,779,229 $ 15,909,980 $859,689,210 6.526 1.89%
Line
No Tariff Description
1 Uniform Tariff Rates:
2 Residential Service
3 Master Metered Mobile Home Park
4 Residential Service Energy Watch
5 Residential Service Time-of-Day
6 Small General Service
7 Large General Service
8 Dusk to Dawn Lighting
9 Large Power Service
10 Agricultural Irrigation Service
11 Unmetered General Service
12 Street Lighting
13 Traffic Control Lighting
14 Total Uniform Tariffs
15
16 Special Contracts:
17 Micron
18 JRSimplot
19 DOE
20 Hoku
21 Total Special Contracts
22
23
24 Total Idaho Retail Sales
Power Supply Cost Summary.
Case No. IPC-E-12-17
Base Costs are Redistributed
Description Projection Base Difference or Allocated Shared Idaho Customer Idaho
or Actual Initial Amount to Other with Revenue PCA
Jurisdictions Shareholders Requirement Rates
($) ($) ($) ($) ($) ($) (0/kWh)
Forecast or Projection (2012-2013) I Projection I Base Difference
Acct. 501 - Coal 147,503,921 167,718,084 (20,214,163) (1,010,708) (960,173) (18,243,282)
Acct. 536 - Water for Power 2,521000 1828,640 692,360 34,618 32,887 624,855
Acct. 547- Natural Gas 52,250,517 6,062,472 46,188,045 2,309,402 2,193,932 41,684,711
Acct. 555- Purchased Power (Non- PURPA) 41,169,588 66,689,601 (25,520,013) (1,276,001) (1,212,201) (23,031,812)
Acct. 565- Transmission Wheeling 7,554,520 8,262,000 (707,480) (35,374) (33,605) (638,501)
Acct. 447-Opportunity Sales Revenues (110,167,401) (92,642,114) (17,525,287) (876,264) (832,451) (15,816,572)
Acct. 442- Hoku First Block Energy Revenue (6,765,150) (23,921,466) 17,156,316 857,816 814,925 15,483,575 0.0005
Acct. 555- Purchased Power (PURPA) 129,590,113 62,851,454 66,738,659 3,336,933 0 63,401,726 0.4830
Demand Response Incentive Payments 14,723,210 11,252,265 3,470,945 0 0 3,470,945 0.0264
Sub-Total 278,380,318 208,100,936 70,279,382 3,340,422 3,314 66,935,646 0.5099
True Up (2011-2012) Actual Base I Difference
Revenue from Forecast Rate 7,823,682 0 7,823,682 0 0 7,823,682
Load Change Adjustment 12,621,398 0 12,621,398 631,070 599,516 11,390,811
Acct. 501 - Coal 122,922,864 167,418,061 (44,495,197) (2,224,760) (2,113,522) (40,156,915)
Acct. 536 -Water for Power 2,577,915 1,825,371 752,544 37,627 35,746 679,171
Acct. 547- Natural Gas 10,877,122 6,051,627 4,825,495 241,275 229,211 4,355,009
Acct. 555- Purchased Power (Non- PURPA) 62,156,365 66,570,302 (4,413,937) (220,697) (209,662) (3,983,578)
Acct. 565 - Transmission Wheeling 6,516,274 8,247,222 (1,730,948) (86,547) (82,220) (1,562,180)
Acct. 447 - Opportunity Sales Revenues (96,750,895) (92,476,391) (4,274,504) (213,725) (203,039) (3,857,740)
Acct. 442- Hoku First Block Energy Revenue (14,477,351) (5,773,675) (8,703,676) (435,184) (413,425) (7,855,068)
Acct. 555- Purchased Power (PURPA) 103,846,995 62,739,020 41,107,975 2,055,399 0 39,052,576
Emission Allowance Sales Credit (25,202) 0 (25,202) (1,260) (1,197) (22,745)
REC Sales (5,521,597) 0 (5,521,597) (276,080) (262,276) (4,983,241)
Interest During Deferral Period (163,234) 0 (163,234) 0 0 (163,234)
Demand Response Incentive Payments 0 2,715,842 (2,715,842) 0 0 (2,715,842)
Sub-Total 196,756,971 217,317,379 (20,560,408) (492,883) (2,420,867) (17,646,658) (0.1340)
(l
t.J P CD
'n 1
y
True Up of the True Up (Reconciliation of the True Up)
Unrecovered True Up of the True Up Amount Carried Forward
Other Limited Term Adjustments:
PCA True Up Amount Transferred
Emission Allowances - ON 32250
DSM Rider Funds - ON 32217
Interest During Amortization
Revenue from True Up & True Up of the True Up Rates
Sub-Total
Total Power Cost Adjustment (PCA)
Initial Amoj
(18,152,666) (18,152,666)
4,181,114 4,181,114
(491,989) (491,989)
10,000,000 10,000,000
(66,926) (66,926)
(634,702) (634,702)
(5,165,169) 0 0 (5,165,169) (0.0392)
F-0-3-3-67-1
HISTORY OF PCA AMOUNTS
2012 - 2013 PCA Year
)VV.'J
250.0
200.0
150.0
w
0 CL
1::.:
'1H!ii'Yi 1
(100.0) 1993 1 1994 1995 1 1996 1 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
UPCAAmounts 4.9 1 14.7 8.1 1 (17.6) 1 (16.7) 17.3 (23.2) 14.8 220.2 240.2 81.3 70.8 73.1 (46.8) 30.7 106.0 194.0 41.9 (50.4) 43.0
t'J
PCA Year
-
CD
y
0
0
C,)
0
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 15TH DAY OF MAY 2012,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-E-12-17, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
JULIA A HILTON
LISA D NORDSTROM
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
EMAIL: [e-mail]
[e-mail]
PETER J RICHARDSON
GREGORY M ADAMS
RICHARDSON & O'LEARY
P0 BOX 7218
BOISE ID 83702
EMAIL: [e-mail]
greg(2richardsonando1eary.corn
SCOTT WRIGHT
GREG SAID
IDAHO POWER COMPANY
P0 BOX 70
BOISE ID 83707-0070
EMAIL: gsaidcidahopower.com
swrightcidahopower.com
DR DON READING
6070 HILL ROAD
BOISE ID 83703
EMAIL: dreading,mindspring.com
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