20040514Comments.pdf

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L=..aDONALD L. HOWELL, II
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 3366
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Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
IDAHO POWER COMPANY FOR AUTHORITY
TO IMPLEMENT POWER COST ADJUST -
ME NT (PC A) RATES FOR ELECTRIC
SERVICE FROM MAY 16, 2004 THROUGH
MAY 31,2005.
CASE NO. IPC-04-
COMMENTS OF THE
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 responds to the Notice of
Application and Notice of Modified Procedure issued in Order No. 29478 on April 22, 2004.
BACKGROUND
On April 15 , 2004, Idaho Power Company filed an Application for authority to implement
its annual power cost adjustment (PCA) rates. Since 1993 the PCA mechanism has permitted Idaho
Power to adjust its rates upward or downward to reflect the Company s annual "power supply
costs." Because of its predominant reliance on hydroelectric generation, Idaho Power s actual cost
of providing electricity (its power supply costs) varies from year-to-year depending on changes in
stream flow and the market price of power. The PCA is designed to allow the Company to recover
(or rebate) 90 percent of the above (or below) normal power supply costs experienced by the
STAFF COMMENTS MAY 14, 2004
Company for providing service in Idaho. The PCA rate is combined with the Company s "base
rates l to produce a customer s overall energy rate.
STAFF ANALYSIS
As filed by the Company, this year s PCA has three components: 1) a projection
component; 2) a true-up component that corrects for the previous years projection error; and 3) a
true up of the previous year s true up that is a final correction.
The PCA Projection
The National Weather Service Northwest River Forecast Center in Portland, Oregon
forecasts the April through July Brownlee Reservoir inflow this year to be 3.13 million acre-feet
(mat). This is fifty percent (50%) of the normal expected inflow. A regression equation developed
from the results of the general rate case power supply model is used to project "Net Power Supply
Costs.See Order No. 24806. Using the forecasted 3.13 mafand the regression equation, Staff
calculates Net Power Supply Costs for April 2004 through March 2005 , to be $83,410 363. As
authorized by Commission Order, Staff increased the calculated Net Power Supply Costs by
expected qualifying facility costs of$46,413 057 to generate an expected PCA expense of
$129 823,420. See Staff Attachment A. This is approximately $35.7 million above normal on a
total company basis. Staff found that its calculation agreed with Idaho Power s calculation. The
calculation of the projection rate component is shown on lines 1 through 6 of Attachment C, where
the projection rate component is calculated to be 0.2499~/kWh. Staffs calculation of the projection
rate component agrees with Idaho Power s calculation.
The PCA True up
Exhibit No.4 to Idaho Power witness Said's testimony illustrates the calculation of the
2003-2004 True up. Staff reviewed Idaho Power s calculation and agrees with its result; Idaho
Power under collected power supply costs by $44 285 289 last year in Idaho and, therefore
1 The Commission authorizes base rates in a general rate case. The Commission expects to establish new base rates
effective June 1 2004, as a result of the Company s current general rate case, IPC-03-13.
STAFF COMMENTS MAY 14, 2004
customers owe that amount. Staff Attachment B shows the same calculation. The approximate
$44.3 million true up is composed as follows:
Last Year s Projection Revenues
90 % of Last Year s Above Normal Power Supply Costs
Above Normal PURP A Facilities Costs
True up Interest
IDACORP Energy Credit
$(28.8 Million)
$ 69.9 Million
$ 4.7 Million
$ 0.5 million
$ (2.0 Million)
-----------------
Total True up $ 44.3 Million
The true-up rate component of 0.3661~/kWh is calculated on line 8 of Attachment C to these
comments.
The PCA True up of the True up
As the result of a settlement stipulation reached among the parties in the Company s last
PCA case (Case No. IPC-03-5) several changes were made to the PCA mechanism. See Order
No. 29334. One of these changes is that beginning with this PCA filing, under or over collection of
the true-up amount will be tracked and trued up. The true-up amount set for recovery in the last
PCA case was $38 658 298 and the established true-up rate was 0.3579~/kWh. Including interest
considerations, the approved rate under recovered the true-up amount by $556 693. As shown on
Attachment C, line 9, this becomes the true up of the true up PCA rate component ofO.OO46~/kWh.
This is the same rate the Company calculated.
PCA Rates
The calculated PCA rate of 0.6206~/kWh is the sum of the three components listed above
(0.2499 + 0.3661 + 0.0046 = 0.6206). However, for reasons stated in its Application, the Company
does not wish to increase PCA rates at this time. Therefore, the Company proposes to continue the
existing PCA rate ofO.6039~/kWh for another year. The continuation of the lower rate is expected
to cause the Company to under recover the true up by approximately $2 million, which it proposes
to recover next year.
Also as a result of the settlement stipulation previously discussed, three rate classes are
scheduled to receive an additional credit. These credits are specified in the stipulation. The credits
and Company proposed PCA rates for these three schedules (Schedule 7 (small general),
STAFF COMMENTS MAY 14, 2004
Schedule 19 (large power) and Schedule 24 (irrigation)) are shown on lines 16, 17 and 18 of
Attachment C, respectively. Line 19 shows the Company proposed PCA rate for all other
schedules.
In addition to the Company proposed PCA rate credits just discussed, the Staff believes that
customers taking service on those 3 schedules deserve an additional credit. This additional credit is
designed to refund to customers the over-collection that the Company will receive as a result of
current PCA rates being extended from May 15 , 2004 through May 31 2004.2 These amounts are
associated with the carry-over portion of the 2002/2003 PCA rate, which is why they apply only to
Schedules 7, 19 and 24 and it is also why they will not be captured in the true up of the true up.
The total amount of the over-collection is estimated by Staff to be at $605 689. This
estimate is based on one-half of May 2003 actual sales and the carry-over portion of the PCA rate
currently in effect. If this adjustment is not made, the over-collection amounts will be a windfall to
the Company. Any other over collected amounts associated with the two-week extension of the
2003/2004 PCA rates are captured in the true up of the true up and will be refunded in next years
PCA. Attachment C, lines 22 through 24, show Staff s proposed rate calculation. Column (d)
shows the estimated amount of the over-collection, Column ( e) shows expected sales for each
schedule and Column (t) shows the proposed rate credit. Finally, Column (g), lines 22 through 25
shows Staff s proposed PCA rates for the coming year in bold print. These rates are the same as
those proposed by the Company except they include the two-week rate extension credit.
Lines 28 through 34 of Attachment C calculate total expected PCA revenue for the coming
year of $70 643 094.
Attachment D shows the impact on each customer class of the proposed PCA rate change
measured from existing rates that include the current PCA. It shows decreases (i., credits) for the
Irrigation Service class (-16.25 %), Large Power Service class (-90 %) and the Small General
Service class (-78 %). All other class rates remain unchanged. Attachment E shows the impact
on each customer class of the proposed PCA rate change measured from base rates that do not
include current PCA rates. Attachment E shows, in Column 5 , the above normal power supply cost
proposed for recovery through the PCA. Normal water conditions and zero true-up balances could
eliminate these above normal costs in a future PCA case. At the conclusion of the current general
rate case new base rates will be established. The new base rates may cause the percentages in
2 The Commission authorized the two-week extension in Order No. 29478 at 4-
STAFF COMMENTS MAY 14, 2004
Column 8 to decrease, but the amounts shown in Column 5 that are based on normal consumption
will remain the same.
STAFF AUDIT
During the course of the PCA audit, Staff reviewed Company information including the
Company s Risk Management Committee (RMC) activities, the power purchases and sales
Danskin expenses and production, and an outage at the Company s Valmy 2 plant in Nevada. The
findings of the Staff audit are listed below.
Risk Management Activities
Staff reviewed the Risk Management operating plans, meeting minutes and related
materials. The Risk Management Policy Guidelines in place for the 2003-2004 PCA year include:
TIER One System Risk Limit of$100 Million; TIER Two Volumetric Limit of +/- 100 MW; TIER
Three Price Floor Limits; and a Transaction Price Notification limit of $60/MWh. It appears that
the Risk Management Committee (RMC) decisions have been consistent with the Policy Guidelines
for this PCA year and that the Company has been implementing the recommendations of the RMC.
During this PCA year the risk management methodology has helped to stabilize rates while
reducing the upside risk to customers. During the month of July 2003 , the Company made
purchases that required Commission notification because they were above the $60/MWh threshold
amount. Idaho Power also notified the Commission in a timely fashion.
A TIER One violation was also triggered during this PCA year. Idaho Power notified the
Commission and RMC Customer Advisory Group members of the violation and explained the
proposed activities to address the breach.
Power Purchases and Sales
Staff has reviewed the power purchases and sales for the PCA period. Staff has also
reviewed the written purchase and sale policies and found them to be reasonable and prudent. The
purchases and sales were made with a variety of credit worthy partners on a timely basis and there
were no transactions with IDACORP Energy or other affiliates during this PCA period.
ST AFF COMMENTS MAY 2004
Danskin and Fuel Expenses
The Danskin peaking facility ran more this PCA year than in the 2002 PCA year.
According to the Company, the plant was required to run more last summer because Northwest
power was not available or there was a transmission constraint that did not allow the import of
power. These constraints may have been exacerbated by the outage at the Valmy 2 plant. Danskin
also ran for at least a few hours during most of the shoulder months for testing and other purposes.
The total Danskin production during the PCA year was 41 197 MWhs. The cost for natural gas was
approximately $65 per MWh over the period.
Valmy 2 Plant Outage
During last summer, Idaho Power experienced an unexpected plant outage at the Valmy 2
plant. The plant is a 522 MW coal-fired power plant and is jointly owned (50% each) with Sierra
Pacific. Sierra Pacific operates the plant under a management agreement that allows Idaho Power
an equal opportunity and responsibility to review operations and set policies. Idaho Power has a
management team that oversees the coal-fired facilities and reviews the actions of the managing
partner, plant policies and the costs of all its shared thermal plants through oversight investigations
and plant visits.
On June 26 2003, the generator was accidentally energized and sustained severe damage.
Because of the accident, the plant was out of service from June 26 until September 8 , 2003. In
addition to the damage to the generator, the Company was required to purchase replacement power
during the plant outage at rates significantly higher than the usual variable costs for Valmy. Idaho
Power has included these additional power purchases and associated carrying costs in this PCA to
be passed on to customers.
The sequence of events that led up to the accident is clearly documented by the investigation
team formed after the accident. Staff has attached an IDACORP internal audit report titled "Valmy
Plant Unit 2 Inadvertent Energization Incident" as Confidential Attachment F.4 The report also
included a letter from E.M. Brinson, PE, an Idaho Power consultant who reviewed the report and
conducted his own investigation into the incident. Mr. Brinson concluded that the Company
report into the incident was indeed an accurate representation of the events and the factors that
3 During the 2003 PCA year, Danskin produced 34,453 MWh compared to 27 789 MWh during the 2002 PCA year.4 The document was provided to Staff in response to an audit request and was marked by Idaho Power as
Confidential. "
STAFF COMMENTS MAY 14, 2004
contributed to the incident. A summary of the important events that led up to the accidental
energization is set out below.
On June 16, the Valmy Plant Unit 2 was taken offline to repair an air heater bearing. On the
morning of June 17, the Unit 2 disconnect switch was "opened", isolating Unit 2 from the
switchyard. Later that day Sierra Pacific Substation Control and Test (SCAT) personnel made
several modifications to the generator breaker control wiring, allowing power circuit breakers
numbers 3600 and 3601 to be closed. Apparently, modifying the control wiring has been a common
practice at Valmy to increase reliability for Sierra Pacific s transmission system when a Valmy
generating unit is offline. While these modifications may increase reliability for the transmission
system, they also defeat specifically engineered protections that were intended to prevent accidental
energization of the generator.
On June 26 2003 , after repairs to the air heater bearing were complete, the Valmy 2 unit
was brought on line. However, the safety protections were not returned to the normal operating
condition. As a result, the generator was accidentally energized and motored5 for approximately
minutes until the control center personnel realized the problem and stopped the generator.
The motoring damaged both the steam turbine and the generator. Damage also occurred in
all six turbine bearings, the generator rotor, the generator retaining rings, stator wedges and the
steam turbine blades. The causes of the incident were clearly identified in the report prepared by
IDACORP internal auditors, Sierra Pacific personnel and the independent consultant. The causes
included an apparent failure to follow established safety procedures, a lack of proper supervision
and training, and poor communications between proj ect personnel.
According to Idaho Power, its share of the equipment repairs amounted to approximately
$1.3 million.6 While the equipment damages are serious and expensive, another financial impact
was caused by the lack of Valmy Unit 2 generation through the summer months. The outage forced
Idaho Power to purchase approximately 133.5 MW every hour, or forgo additional power sales that
could have been made with excess generation from June 26 through September 9 2003. The net
5 Generator motoring occurs when the generator is excited and using power instead of generating power. It can cause
rotation of the generator while under a no-load condition. Often motoring occurs with the loss of the prime mover, in
this case steam. The loss of the prime mover and a no-load condition can result in the generator spinning beyond its
safe speed. Motoring is a significant safety concern and specific features are generally built in to protect against such an
event.
6 Idaho Power and Sierra Pacific have submitted claims to various insurance carriers to recover costs associated with the
incident. While some recovery is expected for the equipment costs, it appears that there is no recovery for replacement
power from insurance carriers.
STAFF COMMENTS MAY 14, 2004
cost of the replacement power and lost sales to Idaho Power was initially estimated by the Company
to be approximately $6.9 million. However, the Company arrived at this estimate by simply using
the average daily Mid-C index prices during the relevant period. The Company s estimate was not
based on the actual prices it paid for term purchases, Danskin costs, and real-time purchases used to
replace Valmy power at significantly higher costs.
Idaho Power advised Staff that it has not attempted to calculate the exact amount of
additional power supply costs due to the incident and has simply included all costs in the PCA
accounts for recovery from customers in its current PCA Application. It is Staff s position that the
PCA was established to adjust for changes in water conditions and energy market prices. In other
words, weather related conditions and power supply costs beyond the control of the Company.
was not designed to automatically flow through costs associated with this type of event. Absent the
PCA, these costs would not even be considered without special application from the Company.
Presumably, recovery from customers, if allowed at all, would only occur after thorough review.
After reviewing the Company s report on the Valmy 2 outage , Staff recommends that the
Commission open a case to formally review the incident and its financial impacts. The incident
could have been avoided at several junctions had personnel followed established procedures. Even
though Sierra Pacific personnel operate the plant, Idaho Power is an equal partner in oversight and
management of the plant. Idaho Power has the opportunity and obligation to review written
operating procedures and make sure they are being followed. Idaho Power has since reviewed its
own management policies and determined that more oversight of Val my is necessary.
Given the uncertainly regarding the magnitude of Valmy power replacement costs, Staff
further recommends that the Commission reserve recovery of the replacement power costs due to
the incident in the amount of at least $9 million until an investigation is completed. Finally, Staff
recommends that current PCA rates (with the 3 class exceptions) be continued, but any adjustments
in power cost recovery resulting from the formal investigation be carried over to next year s PCA
case. This Staff recommendation should not be construed as a disallowance that would require
write-off at this time. The need for further review dictates setting the amount aside and deferring a
Commission decision until the investigation is complete.
STAFF COMMENTS MAY 14, 2004
RECOMMENDATIONS
Based on the information reviewed by Staff and presented in these comments, Staff
recommends the following:
1. That Idaho Power be allowed to implement a basic PCA rate ofO.6039~/kWh for
all schedules except Schedules 7 , 19 and 24, as the Company proposes in its filing.
2. That PCA rates for the three schedules should be as follows: Schedule 7 -
5761~/kWh; Schedule 19 - 0.5730~/kWh; and Schedule 24 - 0.4976~/kWh.
These rates are lower than those recommended by the Company due to the two-week
rate extension credit discussed in these comments.
3. That these rates become effective June 1 2004 as proposed by the Company.
4. That the Commission open a case to formally review financial impacts of the Valmy
incident. Given the uncertainty regarding the magnitude of Val my 2 replacement
power costs, Staff further recommends that the Commission reserve recovery of the
replacement power (at a minimum of $9 million) pending further investigation.
Finally, Staff recommends that any adjustments in power cost recovery resulting
from the formal investigation be carried over to next years PCA without adjustment
for this issue in the Company s current PCA rate proposal.
Respectively submitted this J'IIJ.. day of May 2004.
Donald L. How I, II
Deputy Attorney General
Technical Staff:Alden Holm
Keith Hessing
i: umisc/commen tslipcO4. 9dhahkhmp
ST AFF COMMENTS MAY 14, 2004
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TRUE-UP CALCULATIONS FOR 2003 - 2004
FOR
IDAHO POWER COMPANY PCA
CASE NO. IPC-04-
Staff Case
1 Jurisdictional Allocation Factor 85,
2 Sharing Percentage 90,
2003 2003 2003 2003 2003 2003 2003
DESCRIPTION Units APR MAY JUN JUL AUG SEPT OCT
PCA Revenue
6 Normalized Firm Load MWh 991 176 033,117 143,545 352 219 1,422 263 206 799 112 398
7 PCA Component Rate m/KWh 156 313 2.460 2.460 2.460 2.460 2.460
8 Revenue Allocated at 85,816,429 031 075 391 153 827,490 973 952 523,417 326 024
10 Load Change Adjustment
11 Actual Firm Load MWh 005,095 206,403 513 516 725 942 511 642 220,400 085 155
12 Normalized Firm Load MWh 991 176 033,117 143,545 352 219 1,422 263 206 799 112 398
13 Load Change MWh 919 173 286 369 971 373,723 379 601 (27 243)
14 Expense Adjustment (~16.84)(234 396)918 136)230 312)293,495)505 142)(229,041)458 772
16 Non-QF PCA
17 ACTUAL:
18 Purchased Water
19 Fuel Expense - Coal 211 698 167 053 001 815 007 861 500 113 9,420 570 572,470
20 Fuel Expense - Gas 219 529 464 928 396 519 500 000 928 967 248,489 213 635
21 Non-Firm Purchases 957 265 189 932 091 343 072 038 970 750 132 353 184 201
22 Surplus Sales (9,399,118)(5,354 647)258,613)(1,460 784)(3,880,396)098,480)859 374)
23 Expense Adjustment (~16,84)(234 396)918 136)230 312)(6,293,495)505 142)(229 041)458 772
Sub-Total 754 978 549 130 000 752 825,620 014 292 11,473,891 569 704
26 BASE:
27 Fuel Expense 341 000 293 000 843,000 076,000 6,445,000 587 000 026,000
28 Non-Firm Purchases 339 000 356 000 872 000 2,473,000 252 000 615 000 162 000
29 Surplus Sales (3,195,000)(597 000)(208 000)(142 000)(595 000)570,000)022 000)
30 Surplus Sales Adder (826 063)(979,683)(693,151)(600 808)(745,141)(664 245)(742 240)
Sub-Total (341 063)072 317 813 849 806 192 356,859 967 755 2,423 760
33 Change From Base 096 041 2,476,813 186,903 25,019,428 657,433 506 136 145,944
34 Deferral (Shared and Allocated)838,471 894 762 027 981 19,139,862 13,507 936 742 194 936,647
36 QF Deferral
37 Actual (incl. Meridian Amort,356,255 3,448,832 5,441 988 862 008 505 591 203 308 805,035
38 Base 038 265 024 735 108,325 317,475 059,785 531 295 2,438,425
40 Change From Base 317 990 424 097 333 663 544 533 445,806 672 013 366 610
41 Deferral (Allocated)270 292 360,482 283 614 462 853 378,935 571 211 311 619
43 Credit From IDACORP Energy (166 667)(166 667)(166,667)(166,667)(166,667)(166,667)(166,667)
44 Total Deferral (874 333)503 753,775 608 559 746 253 623,322 755 575
46 Principal Balances
47 Beginning Balance (874 333)(816,830)936 945 20,545,503 291 756 915,078
48 Amount Deferred (874 333)503 753,775 16,608,559 10,746,253 623 322 755,575
49 Ending Balance (874 333)(816,830)936,945 20,545,503 291 756 915 078 670,653
51 Interest Balances
52 Accrual thru Prior Month (1,458)738)858 38,168 90,385
53 Interest ~2% per Year (1,457)361)562 243 , 1 ~3 192
54 Prior Month's Interest Adj.(1)
55 Total Current Month Interest (1,458)279)596 311 217 58,195
56 Interest Accrued to Date (1,458)738)858 38,168 385 148,580
57 Balance (True-Up & Interest)(874 333)(818 288)934 207 549 361 329 925 005,464 819 233
59 True-Up of the True-
60 True-Up Revenues 274 737 221 294 899,594
62 Beginning Balance 38,658,298 38,658 298 38,512,422
63 Interest ~2% per Year 64,430 64,430 187
64 Revenue Applied to Interest 128 861 187
65 Revenue Applied to Balance 145 876 157 107
66 True-Up of the True-Up Balance 38,658,298 512,422 355 315
Note: Negative amounts indicate benefit to ratepayers
Attachment B
Case No. IPC-04-
Staff Comments
05/14/04 Page 1 of 2
274,737 3,221,294 4.899,594
38,658,298 38,658 298 38,512,422 64,430 64,430 64 1870 128 861 64 1870 145 876 3,157 107
38,658,298 38 512,422 35 355 315
38,658,298
64,430
38,658,298
U:\khessin\ipce0409\StaffCase\TRUE UPS & RATES 5/13/2004 KDH
TRUE-UP CALCULATIONS FOR 2003 - 2004
FOR
IDAHO POWER COMPANY PCA
CASE NO. IPC-04-
Staff Case
85,
90.
Units
MWh
m/KWh
MWh
MWh
MWh
2003
NOV
030,835
2.460
155,4 76
122 562
030,835
727
(1,544 683)
366,767
278,959
991,573
150,465)
544 683
942,151
1 Jurisdictional Allocation Factor
2 Sharing Percentage
DESCRIPTION
5 PCA Revenue
6 Normalized Firm Load
7 PCA Component Rate
8 Revenue Allocated at 85.
10 Load Change Adjustment
11 Actual Firm Load
12 Normalized Firm Load
13 Load Change
14 Expense Adjustment ((Q)16,84)
16 Non-QF PCA
17 ACTUAL:
18 Purchased Water
19 Fuel Expense - Coal
20 Fuel Expense - Gas
21 Non-Firm Purchases
22 Surplus Sales
23 Expense Adjustment ((Q)16.84)24 Sub-Total
26 BASE:
27 Fuel Expense
28 Non-Firm Purchases
29 Surplus Sales
30 Surplus Sales Adder31 Sub-Total
33 Change From Base
34 Deferral (Shared and Allocated)
36 QF Deferral
37 Actual (inc\. Meridian Amort.
38 Base
40 Change From Base
41 Deferral (Allocated)
43 Credit From IDACORP Energy
44 Total Deferral
46 Principal Balances
47 Beginning Balance
48 Amount Deferred
49 Ending Balance
51 Interest Balances
52 Accrual thru Prior Month
53 Interest (Q)2% per Year
54 Prior Month's Interest Adj,
55 Total Current Month Interest
56 Interest Accrued to Date
57 Balance in All Accounts
59 True-Up of the True-
60 True-Up Revenues
62 Beginning Balance
63 Interest (Q)2% per Year
64 Revenue Applied to Interest
65 Revenue Applied to Balance
66 True-Up of the True-Up Balance
68 Note: Negative amounts indicate benefit to ratepayers
909,000
345,000
(3,883,000)
625,640
745,360
196,791
740,545
169,568
539,895
629,673
535,222
(166,667)
953,625
36,670,653
953,625
39,624 277
148,580
118
61,117
209,697
39,833,974
248,526
17,978,914
965
29,965
218,561
760 353
U:\khessin\ipce0409\Staff Case\TRUE UPS & RATES 5/13/2004 KDH
2003
DEC
162 545
2.460
2,430,882
217 213
162 545
668
(920 609)
185 816
225,146
12,167,472
(6,179,519)
920,609
13,478 306
127 000
844 000
809 000)
739,128
4,422 872
055,434
927,407
224 029
713,885
510,144
433,622
(166,667)
763,481
39,624,277
763,481
44,387,758
209,697
66,040
66,099
275,796
663,555
376,002
760 353
24,601
601
351,401
11,408,951
2004
JAN
229,083
2.460
570,013
263,507
229,083
34,424
(579 700)
085,227
213,065
800,202
618 339)
579,700
900,455
051 000
879,000
978,000)
799,267
152,733
747 722
162,007
965 780
567,845
397 935
338,245
(166,667)
763 572
387 758
763,572
47,151 331
275,796
73,980
954
349,750
501 081
727 004
11,408,951
19,015
19,015
707 989
700,962
2004
FEB
162,223
2.460
2,430,208
119,830
162 223
42,393
713,898
692,488
237 681
380 529
(6,381 747)
713 898
642,849
051 000
642,000
(2,781,000)
769,197
142 803
500,046
3,442 535
911 118
1,459,785
451,333
383,633
(166,667)
229,293
47,151 331
229 293
48,380,624
349,750
78,586
78,579
428,329
48,808,953
752 687
700,962
835
835
739,852
961 110
2004
MAR
106,080
2.460
312,813
025,276
106,080
80,804
360,739
938,020
223,887
701,895
(17,079,326)
360,739
854,785)
737 000
296 000
742 000)
889,476
1,401 524
(3,256,309)
(2,491 076)
745,337
314,445
430,892
366,258
(166,667)
604 298)
48,380,624
604,298
776,326
428,329
80,634
637
508,966
44,285,292
3,411 019
961,110
602
602
3,404,417
556,693
TOTALS
13,952 283
28,788,931
15,016,541
952 283
064,258
(17 922 105)
96,149,898
150,805
117 639,553
(70,720,808)
922,105
130,297 343
61,486,000
075,000
(24 522 000)
074 038
38,964 962
332 381
69,869,272
39,638,849
114 160
524 689
695,986
(2,000,000)
776,326
43,776 326
508,688
278
508 966
285,292
38,575,925
474,320
38,101 605
Attachment B
Case No. IPC-04-
Staff Comments
05/14/04 Page 2 of 2
2004-2005 PCA - Twelfth Annual
IPC-04-
Staff Case
(a)(b)(c)(d)(e)(f)
(g)
Line Descri tion Units Base Forecast Difference Rate
Projection 2004-2005:
PCA Expense
($)
101 157 129 823,425 722 268
Normalized Energy - Total System (MWH)863,484 863,484
Energy Rate (i/kWh)73154 00924 27770
Sharing Percentage
(%)
90%
Energy Rate Difference (i/kWh)249932609 2499
ill MWh (ct/kWh
True-of 2003-2004:285 289 096 838 660897914 3661
True-of the True-2002-2003:556 693 096 838 046019712 0046
PCA Rates:
Calculated PCA Rate Adj, From Base (i/kWh)6206
Proposed PCA Rate Adj, from Base (i/kWh)6039
PCA Rate Currently in Effect (i/kWh)6039
Difference - Last Year to This Year (i/kWh)0000
N, 29334 (lPC-03-5) Credits & Rates:Credit Rate
Schedule 7 - Small General Service (i/kWh)(0,0189)5850
Schedule 19 - Large Power Service (i/kWh)(0,0222)5817
Schedule 24 - Irrigation & Pump (i/kWh)(0,0811)5228
All Other Schedules (i/kWh)0000 6039
Credit Rate
Two Week Rate Extension Credits & Rates:ill MWh (ct/kWh)
Schedule 7 - Small General Service 572 265,336 (0,0089)5761
Schedule 19 - Large Power Service 172 939 978 824 (0,0087)5730
Schedule 24 - Irrigation & Pump 409 178 620 931 (0,0252)4976
All Other Schedules 0000 6039
Expected PCA Revenues:Rate Energy Revenue
/MWh MWh ill
Forecast Revenue 2.499 096 838 229,998
True Up Revenue 3.494 096,838 266 352
True Up of True Up Revenue 046 096 838 556,455
Schedule 7 - Small General Service (0,278)265 336 (73 720)
Schedule 19 - Large Power Service (0,309)1 ,978 824 (612 238)
Schedule 24 - Irrigation & Pump (1,063)620 931 723 753t
Total 643,094
35 Note: Negative rates and amounts indicate benefits to ratepayers,
U:\khessin\IPCE0409\Staff Case\TRUE UPS & RATES 5/13/2004
Attachment C
Case No, IPC-04-
Staff Comments
05/14/04
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KD
H
CASE NO. IPC-04-
STAFF COMMENTS
MAY 14, 2004
ATTACHMENT F CONTAINS ALLEGEDLY PROPRIETARY DATA
AND HAS BEEN REMOVED FROM THIS DOCUMENT
CERTIFICATE OF SERVICE
HEREBY CERTIFY THAT I HAVE THIS 14TH DAY OF MAY 2004 SERVED
THE FOREGOING COMMENTS OF THE COMMISSION STAFF IN CASE
NO. IPC-04-, BY MAILING A COpy THEREOF POSTAGE PREPAID TO THE
FOLLOWING:
BARTON L KLINE
MONICA MOEN
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
GREGORY W SAID DIRECTOR
REVENUE REQUIREMENT
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
CONLEY E WARD
GIVENS PURSLEY LLP
PO BOX 2720
BOISE ID 83701-2720
RICHARD E MALMGREN
MICRON TECHNOLOGY INC
8000 S FEDERAL WAY
BOISE ID 83716-9632
ill ,KodL
SECRETARY
CERTIFICATE OF SERVICE