20070514Comments.pdf

DONALD 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 ADJUSTMENT)
(PCA) RATES FOR ELECTRIC SERVICE FROM)
JUNE 1,2007 THROUGH MAY 31 , 2008.
CASE NO. IPC-07-
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission, by and through its Attorney of
record, Donald L. Howell, II, Deputy Attorney General, respectfully submits the following
comments in response to Order No. 30302, the Notice of Application and Notice of Modified
Procedure issued on April 18, 2007.
BACKGROUND
On April 13, 2007, Idaho Power Company filed its annual Power Cost Adjustment (PCA)
Application. 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 cost) varies from year-to-year depending on changes in streamflow and the market price of
STAFF COMMENTS MAY 14 2007
power. The annual PCA surcharge or credit is combined with the Company s "base rates l to
produce a customer s overall energy rate.
In this PCA Application Idaho Power requests recovery of $30.7 million of above normal
power supply costs. The Company estimates that this represents a $77.5 million increase in
revenues from existing PCA rates (which are below normalized base rates), or an average increase
in rates of 14.5%. Attachment A to these comments is a graphic that shows the history ofIdaho
Power s residential energy rates and identifies the PCA component.
STAFF AUDIT AND ANALYSIS
The 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. Set out below are the Staff's comments on the three PCA components.
A. 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 3.30 million acre-feet
(mat). This is only 52% of the average inflow. A regression equation developed from the results of
a power supply model run is used to project "Net Power Supply Costs.See Order No. 24806 and
Staff Attachment B. Using the forecasted 3.30 maf and the regression equation, Staff calculates Net
Power Supply Costs for April 2007 through March 2008, to be $75,497 940. As authorized by
Commission Order, Staff increased the calculated Net Power Supply Costs by expected PURPA
qualifying facility purchases of $54 632 157 and reduced the amount by the expected net benefit of
cloud seeding $895,462 ($1 004 538-900 000) to generate an expected PCA expense of
$129 234 635. This is approximately $28.3 million above normal power supply cost levels 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 0.1888 ~/kWh. Staff's calculation ofthe
projection rate component agrees with Idaho Power s calculation.
I Base rates were established by the Commission in Idaho Power Case No. IPC-O5-28.
STAFF COMMENTS MAY 14, 2007
B. The PCA True-up
The PCA True-up captures the difference between the projected power supply costs from the
past PCA year and the actual power supply costs that the Company incurred during that same year.
Rates were set in the previous PCA period to collect or refund to customers the difference between
the projected power supply costs and those costs reflected in rates. The differences between
projected power supply costs and actual power supply costs is the PCA deferral balance. This
deferral balance, when surcharged or refunded to customers is known as the PCA True-up
component.
Exhibit No.3 to Idaho Power witness Schwendiman s testimony illustrates the calculation of
the true-up deferral amount. Attachment D is Staff's calculation of the true-up deferral amount.
Staff found no differences in methodology or amounts from those presented by the Company.
As shown on Page 2 of Attachment D, line 64 in the "Totals" column, the true-up amount
with interest is $42 115 284. The true up amount used by the Company to calculate the true up rate
also included an Emission Allowance tax benefit of $27 025 013 , which is not included in Company
Exhibit No.3 or Staff Attachment D. In rounded numbers the true up amount, including the
emission allowance tax benefit, is composed as follows:
ITEM
Last Year s Projection (Rebate)
90 % of Last Year s Above Normal Power Supply Costs
Last Year s Above Normal PURPA Facilities Costs
Emission Allowance Sales Credit
Miscellaneous Adjustments (Lines 49 50)
mterest
MILLIONS
$ 19.
$ 68.
$ (1.6)
$(42.
$ (1.
$ (0.
---------
True Up Expense (Deferral)$ 42.
Emission Allowance Tax Benefit $(27.
---------
Total True Up Deferral with Emission Tax Benefit $ 15.
To verify revenues and costs associated with Idaho Power s true-up deferrals, Staff
conducted an audit of all actual revenues and expenses that occurred during the PCA year. These
revenues and costs included the cloud seeding program, fuel expenses for coal, fuel expenses for
gas, and power purchases and sales. Staff also examined PCA Settlement Agreement Credits from
Order No. 29600, Emission Allowance Sales Credit from Order No. 30041 , and the Risk
STAFF COMMENTS MAY 14 2007
Management operating plans. The following items are included in the PCA true-up:
1. Water Lease Purchases.Idaho Power entered into an agreement to purchase 5 000
acre-feet of water (an acre foot of water is enough water to cover an acre, one foot deep) for $14 per
acre- foot. The total cost of $70 000 was offset by an agreement with Powerex Corporation. In
exchange for the release of the irrigation water, Powerex agreed to pay Idaho Power $7 500. Idaho
Power leased the water from Water District 63 in Lucky Peak Reservoir through the Water Supply
Bank. Although not a normal, recurring PCA line item, the terms of the agreement for the water
lease purchase are reasonable and recovery through the PCA is reasonable because the water is
equivalent to fuel for power. The actual water lease purchase expense of $62 500 is a cost to
customers and is subject to jurisdictional allocation and 90/10 sharing.
2. Cloud Seedin2: Pro2:ram.Idaho Power spent approximately $1 , I 08 094 on cloud
seeding program costs during the prior PCA year. Beginning in October 2006, upon the completion
of the general rate case, IPC-05-28 and the issuance of final order, Order No. 30035 , monthly
cloud seeding expenses and benefits were incorporated into base rates. The net benefit from the
cloud seeding program that is included in base rates forthis deferral year (October 2006 through
March 2007) is $895,462. The actual amount of cloud seeding expense for the PCA period from
April 2006 through March 2007 is $804 603. Actual expenses are less than the net benefit included
in base rates by $90 559. This represents a benefit to customers and is subject to jurisdictional
allocation and 90/10 sharing.
3. Fuel Expense - Coal.A large portion of Idaho Powers electricity comes from thermal
power produced from coal plants. The three coal plants that Idaho Power owns an interest in are
Bridger, Valmy, and Boardman. For the audit period of April 2006 to March 2007 the total coal
expense for all plants in operation was $110 532 921. The total coal expense included in base rates
is $95 138 364. The increase or decrease in the coal expense from base rates is included in the PCA
for recovery from or refund to customers. This year s PCA deferral balance includes a difference
between costs currently included in rates and actual costs of$15 394 557. This cost is subject
jurisdictional allocation and 90/10 sharing.
4. Fuel Expense - Gas.Idaho Power owns two gas-fired combustion turbine generating
plants, Danskin and Bennett Mountain. These plants are both located near Mountain Home and
account for 100% of gas usage. For the audit period of April 2006 to March 2007 the total variable
gas and gas transportation expense for both plants was $8 181 907. The total gas and gas
transportation expense included in base rates is $4,451 500. The increase or decrease in gas
STAFF COMMENTS MAY 14 2007
expense from base rates is included in the PCA for recovery from or refund to customers. In this
year s PCA deferral balance, the gas expense that is included for future recovery from customers is
730,407 and is subject to jurisdictional allocation and 90/10 sharing.
5. Power Purchases and Sales.During the PCA year ending March 31 , 2007, the
Company sold surplus power totaling $205 529 288, while total power purchases, excluding
PURPA contracts, were $224 881 906. The total surplus sales included in base rates is $64 162 300
and the total power purchases included in base rates is $11 842 800. The increase or decrease in the
power sales and purchases from base rates is included in the PCA for recovery from or refund to
customers and is subject to jurisdictional allocation and 90/10 sharing. Actual surplus sales
exceeded base amounts by $141 366 988. This cost difference is a benefit to customers. Actual
purchased power amounts exceeded base amounts by $213 039 106. This cost difference becomes a
cost to customers. Net surplus sales (surplus power sales greater than power purchases) of
$52 319 500 are built into base rates. In this PCA year, actual power purchases exceeded surplus
power sales by $19 352 618. The difference between what is built into base rates and the actual
expenditures is captured in the PCA deferral. The net of the power purchase difference and the
surplus sales difference included in this PCA year for recovery (cost to customers) is $71 672 118.
This amount is subject to jurisdictional allocation and 90/10 sharing.
Staff reviewed the power purchases and sales in conjunction with the Company s Risk
Management Operating Plans. Our analysis 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.
6. Emission Allowance Sales Credit.In June 2005 , Idaho Power Company filed an
application requesting blanket authority to sell surplus sulfur dioxide (SO2) allowances; and an
accounting order to provide for recording any sale(s) of such allowances. In Order No. 30041 , Case
No. IPC-05-, the Commission approved and adopted a stipulation providing for the inclusion of
the SO2 allowance sales proceeds in the Company s annual PCA, with 90% ofthe net proceeds to
be passed on to customers, and 10% of the net proceeds to be retained as a shareholder benefit. The
Commission also ordered that the net of tax, 90% portion of the proceeds allocated to customers in
the Stipulation, shall be grossed-up to recognize the tax savings that will accrue when the 90%
credit is provided to customers through the PCA.
STAFF COMMENTS MAY 14 2007
The Commission found the PCA, which is designed to track and true-up abnormal power
supply costs and revenues, to be the logical mechanism to track and distribute proceeds from the
sale of excess SO2 allowances. SO2 allowances are allocated to the Company based on the
ownership and operation of its thermaVcoal powered plants. Excess allowances are a direct result of
many factors associated with the operation of the coal plants including installation of environmental
equipment, the geographic location of the plant, the total time the plant is operated, the nature of the
coal used to fuel the plant, as well as other factors. The allowances accrue as a direct result of plant
operation and ownership in much the same way that energy generated from the plant is used to meet
ratepayer demand and generate surplus sales revenue to offset plant-operating costs. To the extent
that coal costs, environmental costs, and surplus energy sales increase or decrease costs, the cost
differences are captured in the PCA and passed through to customers. It is logical that SO2
allowances pass through in a similar manner.
The net proceeds of the emission allowance sales are $81 647 500. The Idaho jurisdictional
portion is $76 807 243. The 90% portion to be passed on to customers is $69 126 519, which is the
customer benefit after tax amount of$42 101 506 and the tax benefit amount of$27 025 013. The
emission allowance sales credit has been properly accounted for in the PCA deferral calculation.
7. Actual Oualifvin2: Facilities Purchases includin2: Net Meterin2:.A Qualifying Facility
(QF) is a generating facility which meets the requirements for QF status under the Public Utility
Regulatory Policies Act of 1978 (PURP A) and part 292 of the Federal Energy Regulatory
Commission s Regulations (18 c.F.R. Part 292), and which has obtained certification of its QF
status.
There are two types of QFs: cogeneration facilities and small power production facilities.
Qualifying Facilities are sometimes referred to as cogeneration/small power producers or by the
acronym CSPP.
A Cogeneration Facility is a generating facility that sequentially produces electricity and
another form of useful thermal energy (such as heat or steam) used for industrial, commercial
residential or institutional purposes, and otherwise meets the requirements of 18 C.R. ~~
292.203(b) and 292.205 for operation, efficiency and use of energy output.
A Small Power Production Facility is a generating facility whose primary energy source is
renewable (hydro, wind, solar, etc.), biomass, waste, or geothermal resources, and that otherwise
meets the requirements of 18 C.R. ~~ 292.203(a), 292.203(c) and 292.204. Small power
production facilities are limited in size to 80 MW, with the exception of certain types of facilities
STAFF COMMENTS MAY 14, 2007
certified prior to 1995 and designated as "eligible" under section 3(17)(E) of the Federal Power Act
(FPA) (15 D.C. ~ 796(17)(E), which have no size limitation.
Idaho Power has many contracts with qualifying facilities. For the audit period of April
2006 to March 2007 the actual QF expense is $52 320 145. The QF expense included in base rates
is $54 059 005. The increase or decrease in the QF expense from base rates is included in the PCA
for recovery from or refund to customers. In this year s PCA deferral balance, the actual QF
expense was less than the base QF by $1 738 860. This amount is a benefit to customers and
reduces the PCA deferral balance. It is not subject to the 90/10 sharing due to the nature ofPURPA
contracts in that the Company must purchase the output of the Qualifying Facilities. It is subject to
jurisdictional allocation.
8. Settlement A2:reement (Order No. 29600).In a Stipulation involving Idaho Power and
the Commission Staff, both parties agreed on a single comprehensive settlement amount to resolve
several outstanding issues identified in the Stipulation. The parties proposed that the expense
adjustment rate for growth (EARG) component in the PCA would continue at the existing value
16.84 mills per KWH, until the next general revenue requirement case in which the Commission
resets the base rates used for PCA computation purposes. Idaho Power also agreed to provide a
$19.3 million revenue credit to Idaho Power Customers in the Company s PCA. This revenue
credit is a separate $804 166 monthly line item for the months June 2004 through May 2006 in the
PCA true-up calculation and includes interest from June 1 2004 at the PCA carrying charge rate. It
was also agreed that the June 2003 Valmy Unit No.2 incident issues should be resolved in the PCA.
The Commission approved the Stipulation in Order No. 29600 issued in September 2004. Staff
verified that all settlement components of the Stipulation were incorporated in this PCA
Application. The Company has included the proper monthly credit of $804 167 for customers for
the months of April and May of 2006, the final two months of the credit resulting from the
settlement agreement approved in Order No. 29600.
9. Bennett Mountain Credit.In Order No. 29790, Case No. IPC- E-05-1 0, the
Commission approved recovery of Bennett Mountain power plant costs and required that the related
reduction in power supply expense be included in the Company s 2006-2007 PCA. The Company
has included the proper monthly amount to reflect the reduction in power supply costs resulting
from the Bennett Mountain power plant. The credit began in June 2005 and was to run for 12
months. The current deferral balance includes the final two months of the credit. This credit totals
972 and is not subject to the 90/10 sharing.
STAFF COMMENTS MAY 14 2007
In final analysis the PCA Forecast and True Up methodology produced an unexpectedly
large surcharge deferral balance. The PCA year beginning April 2006 was forecasted to be an
above normal water year with below normal power supply costs. A negative forecast rate
component was established which credited customers $19.7 million dollars during the true up
period. Actual power supply costs captured in the true up calculation were $64.5 million above
normal. This amount combined with the forecast credit would have produced a true up amount of
$84.2 million. This is a very large amount to accrue in a good or even normal water year. It is only
the application of$69.1 million of non-recurring SO2 Emission Allowance Sales benefits that
brought the true up amount down to the $15.1 million balance subject to recovery. Without the
Emission Allowance Sales benefits the true up amount and rate would have been extremely high in
a water year that turned out to be about normal. This result was caused by a number of factors.
Base power supply costs are outdated because normalized power supply costs from 2003 are still
being used for PCA purposes. These costs were not updated in the IPC-05-28 general rate case
because of concerns over the AURORA modeled power supply results presented by the Company
in that case. The Load Growth Adjustment Factor is also outdated. The factor used during the true
up period in this case was $16.84 per MWh. At $16.84 per MWh $10.1 million was adjusted out of
the true up amount. The Load Growth Adjustment factor is to be $29.41 per MWh for the next
PCA year, which if used last year would have almost doubled the load growth adjustment amount
(Case No. IPC-06-, Order No. 30215 dated January 9 2007). Staff believes that Load Growth
Adjustment Factors based on real marginal costs could be much higher. Staff plans to review these
and other issues affecting PCA deferral balances as a part ofIdaho Power s upcoming general rate
case.
C. The PCA True-up of the True-up
The PCA true-up of the true-up amount is the difference between what was anticipated to be
collected or refunded when the PCA rate for the true-up was set and what was actually collected or
refunded. When special adjustments are not carried into the true up of the true up calculation, the
amount represents the under or over recovery of the true up amount from the previous year due to a
different amount of kWh being sold than was anticipated in the rate design. The true up of the true
up is a benefit to both the Company and customers because any over-collection is returned to
customers, and any under-collection is recovered by the Company.
The true-up amount set for recovery in last year s PCA case (IPC-06-07) was negative
$39 513 704 and the rate calculated to return that amount to customers was -3113 ~/kWh. With
STAFF COMMENTS MAY 14 2007
other adjustments and interest considerations, the approved rate under refunded the true-up amount
by $7 941 094. As shown on Attachment C, line 13 , this amount is used to calculate the true-up of
the true-up PCA rate component of -0589 ~/kWh. This is the same rate the Company calculated.
PCARATES
The Staff's calculated PCA rate of 0.2419 ~/kWh is the sum of the three components listed
above (0.1888 + 0.1120 - 0.0589 = 0.2419). This rate is shown on Attachment C, line 16. These
are the same rates included in the Company s filing. Staff Attachment E summarizes all PCA rate
components and their associated expense amounts. It also shows amounts allocated to other
jurisdictions and amounts shared with shareholders.
Attachment F shows the proposed average increase above base rates by class and
Attachment G shows the proposed average increase above existing rates by class (last year s PCA
rates to this year s PCA rates). In both of these attachments the percentage increase to larger
customers is substantially more than the average percentage increase. When power supply costs
increase rates, larger customers receive larger than average percentage increases. This results
because large customers have lower rates than smaller customers and an equal cents per kWh
increase makes a larger percentage difference to them than it does to smaller customers whose base
rates are higher.
CONSUMER ISSUES
Idaho Power s PCA Application, filed on April 14, 2007, contained both the customer notice
and press release. Staff reviewed them and determined that they complied with the notice
requirements ofIDAPA 31.21.02.102. The customer notice was mailed with Idaho Power
cyclical billings beginning with the April 26, 2007, statements and ending with the May 24, 2007
statements.
Customers were notified of the Application by bill stuffer and will have until May 14, 2007
to file comments. As of May 8 2007, the Commission had received six comments. It is apparent
from the comments that some customers still do not understand the difference between a PCA filing
and a general rate case filing. Two customers who commented did not have an issue with the
proposed increase although four customers were very unhappy with the possibility of another rate
increase. One customer called the proposal to raise rates a "slap in the face.
STAFF COMMENTS MAY 14 2007
Had there not been the decrease in rates during the past twelve months as a result of last
year s PCA, the PCA request this year would have been an approximate 4% rate increase for
residential customers. Because the roughly 10% rate reduction to residential bills from the 2006
PCA will no longer be in effect after May 31 2007 , residential customers will see a nearly 14% net
rate increase when compared with last year s rates should this year s PCA be approved.
PCA RECOMMENDATIONS
Staff's review identified no adjustments to the Company s calculations. Staffrecommends
that the Commission approve the PCA rates as filed by the Company. Staff recommends that these
PCA rates become effective June 1 2007.
Respectfully submitted this JL/-tk day of May 2007.
Deputy Attorney General
Technical Staff:Keith Hessing
Kathy Stockton
Marilyn Parker
i :umisc/comments/ipceO7.1 Odhkhklsmp.doc
STAFF COMMENTS MAY 14 2007
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MWh
mIKWh
TRUE-UP CALCULATIONS FOR 2006 - 2007
FOR
IDAHO POWER COMPANY PCA
CASE NO. IPC-07-
Staff Case
Units
2006
APR
2006
MAY
881 064
778,002
252,090
142 316
109 774
848 594)
2006
JUN
074 252
507
(2,693,150)
1,455,481
395 617
864
008 110)
2006
JUL
273 977
507
193 860)
751 828
567 783
184 045
099 318)
2006
AUG
295 480
507
247 768)
546 516
1,482 896
620
071 361)
2006
SEPT
168 367
507
929 096)
213 236
185 594
642
(465,491 )
2006
OCT
996 812
507
(2,499 008)
098 789
080 868
921
(301 790)
DESCRIPTION
3 PCA Revenue
4 Normalized Idaho Jurisd, Sales
Forecast Rate
6 Revenue
8 Load Change Adjustment
9 Actual System Firm Load - Adjusted
10 Normalized Firm Load
11 Load Change
12 Expense Adjustment ((Q)16,84)
14 Non-QF PCA
15 ACTUAL:16 Water Lease Purchases 17 Cioud Seeding Program $ 62 223 60 860 25 381 18 559 23,731 42 983 45 175
18 Fuel Expense-Coal $ 5 546 615 6 095 688 7 741 233 10 085 118 10 880 041 10 919 871 9 801 71619 Fuel Expense - Danskin $ 73 786 221 367 336 649 1 319 234 587,423 125 246 (6 289)
20 Fuel Expense - Bennett Mountain $ 132 815 580 697 1 060 247 592 883 0 478 756 260 328
21 Non-Firm Purchases $ 16 805 367 21 235 507 21 621,438 32,424 611 27 710 694 17 680 017 10 081 38222 Surplus Sales $ (33 649 301) (22 745,928) (16 169 244) (7,089 391) (12 918 832) (17,442 355) (13 612 384)
23 Expense Adjustment ((1i116,84) $ (220,065) (1 848 594) (1 008 110) (3 099 318) (1 071 361) (465 491) (301 790)24 Sub-Total $ (11 248 560) 3 599 597 13 607 594 34 251 696 25 211 696 11 339 027 6 268 138
26 BASE:27 Fuel Expense - Coal $ 7 108 200 6 800 600 6 342 000 8 714 200 8 720,308 8,448 908 8 726,40828 Fuel Expense - Danskin $ 264 800 278 500 275 700 279 600 280 800 264,700 272 300
29 Fuel Expense - Bennett Mountain 0 406 100 253 200 256 700 20 900 22,400
30 Non-Firm Purchases $ 28 000 664 100 2 715,400 3 166 600 2 765 200 479 300 35 80031 Surplus Sales $ (9 187 500) (6 566 900) (4 831 500) (2 542 200) (3 601 100) (5 736 200) (5 012 200)32 Cloud Seeding Expense 167,423
33 Cloud Seeding Benefit 0 (316,667)34 Sub-Total $ (1,786,500) 1,176 300 4 907 700 9 871,400 8,421 908 3,477 608 3 895,464
36 Change From Base
37 Emission Allowance Sales Credit38 Sub-Total
40 Deferral (Shared and Allocated)
42 OF Deferral
43 Actual (includes Net Metering)
44 Base
46 Change From Base
47 Deferral (Allocated)
49 Settlement Agreement (ON 29600)
50 Bennett Mtn, Credit (ON 29790)
51 Total Deferral (-6+40+47+49+50)
53 Principal Balances
54 Beginning Balance
55 Amount Deferred
56 Ending Balance
58 Interest Balances59 Accrual thru Prior Month 0 (30 179) (515 182) (737,922) (792 238) (807 259)
60 Interest (Q) 3% per Year 0 (30 178) (35 813) (116 373) (56 201) (12 518) 11 697
61 Prior Month's Interest Adj. (1) (449 190) (106 367) 1 884 (2 503)
62 Total Current Month Interest 0 (30 179) (485 003) (222 740) (54 317) (15 021) 11 697
63 Interest Accrued to Date 0 (30 179) (515 182) (737 922) (792 238) (807 259) (795 562)
64 Balance (True-Up & Interest) $ (12,071,060) (14 355 339) (47 064 419) (23 218 131) (5 799 264)871 566 7 787 504
66 True-Up of the True-
67 True-Up Revenues (Collections)
69 Beginning Balance
70 Adjustments:
71 2005-06 PCA Transfer (ON 30047)
72 Tax Settlement True-Up (ON 29789~
74 Sub-Total
75 Interest (Q) 3% per Year
76 Revenue Applied to Interest
77 Revenue Applied to Balance
78 True-Up of the True-Balance
Note: Negative amounts indicate benefit to ratepayers
U:lkhess;nijpceO710\S(aff Case'TRUE UP 518/2007 KOH
862 931
288
700 248
MWh
MWh
MWh
987 134
974 066
068
(220 065)
(9,462 060)
(9,462 060)
013 419)
294 788
815 766
479 022
450 760
(804 167)
986)
(12 071 060)
2,423 297----.9.
423 297
052 290
457 705
160 399
297 306
279 765
(804 167)
986)
254 100)
699 894
(49 712,488)
(41 012 594)
(34 733 566)
097 652
292 829
(195 177)
(183 662)
(32 224 077)
0 (12 071,060) (14 325,160)
(12,071,060) (2,254 100) (32 224 077)
(12 071 060) (14 325 160) (46 549 237)
619 149
513 298
(39 513 704)
(15 000,406)
(37,501)
(37 501)
656 650
(16 657 056)
1 ,573 833
(16 657 056)
(16,657 056)
(41 643)
(41 643)
615 476
(18 272 532)
946 500
(18 272,532)
(18 272 532)
(45 681)
(45 681)
992 181
(19 264 713)
380 296
380 296
647 673
782,423
540 664
241 759
227 495
069 028
(46 549 237)
069 028
(22,480 209)
966 009)
(19 264 713)
(333 015)
(19 597 728)
(48 994)
(48 994)
917 015)
(17 680 713)
789 788
789 788
219 272
165 189
158 661
528
143
17,473,183
(22 480 209)
473 183
007 026)
118 311)
(17 680 713)
(17 680 713)
(44 202)
(44 202)
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(16 606 604)
861,419
861 419
657,836
608 889
503 768
105 121
919
685 850
007 026)
685 850
678 824
(1,486 632)
(16 606 604)
372,674----.9.
372 674
009 418
919 787
561 853
(642 066)
(604 184)
904 241
678 824
904 241
583 066
169 515)
(15 161,489)
(16 606 604) (15 161,489)
(41 517) (37 904)
(41 517) (37 904)
(1,445 115) (1 131 611)
(15 161,489) (14 029 877)
Attachment D
Case No. IPC-07-
Staff Comments
5/14/07 Page 1 of2
DESCRIPTION
3 PCA Revenue
4 Normalized Idaho Jurisd, Sales
5 Forecast Rate
6 Revenue
8 Load Change Adjustment
9 Actual System Firm Load - Adjusted
10 Normalized Firm Load
11 Load Chan
12 Expense Adjustment (i(Y16,84)
14 Non-QF PCA
15 ACTUAL:
16 Water Lease Purchases
17 Cloud Seeding Program
18 Fuel Expense - Coal
19 Fuel Expense - Danskin
20 Fuel Expense - Bennett Mountain
21 Non-Firm Purchases
22 Surplus Sales
23 Ex ense Ad ustment (rro16,24 Sub-Total
26 BASE:
27 Fuel Expense - Coal
28 Fuel Expense - Danskin
29 Fuel Expense - Bennett Mountain
30 Non-Firm Purchases
31 Surplus Sales
32 Cloud Seeding Expense
33 Cloud Seedin Benefit34 Sub-Total
36 Change From Base
37 Emission Allowance Sales Credit38 Sub-Total
40 Deferral (Shared and Allocated)
42 QF Deferral
43 Actual (includes Net Metering)
44 Base
46 Change From Base
47 Deferral (Allocated)
49 Settlement Agreement (ON 29600)
50 Bennett Mtn, Credit (ON 29790)
51 Total Deferral (-6+40+47+49+50)
53 Principal Balances
54 Beginning Balance
55 Amount Deferred
56 Ending Balance
58 Interest Balances
59 Accrual thru Prior Month
60 Interest i(Y 3% per Year
61 Prior Month's Interest Ad
62 Total Current Month Interest
63 Interest Accrued to Date
64 Balance (True-Up & Interest)
66 True-Up of the True-
67 True-Up Revenues (Collections)
69 Beginning Balance
70 Adjustments:
71 2005-06 PCA Transfer (ON 30047)
72 Tax Settlement True-Up (ON 29789)
74 Sub-Total
75 Interest i(Y 3% per Year
76 Revenue Applied to Interest
77 Revenue Applied to Balance
78 True-Up of the True-Up Balance
TRUE-UP CALCULATIONS FOR 2006 - 2007
FOR
IDAHO POWER COMPANY PCA
CASE NO, IPC-07-
Staff Case
MWh
mIKWh
Units
2006
NOV
912 336
507
287 226)
MWh
MWh
MWh
142 940
122,464
20,476
(344 816)
725
224 908
164,780
662,445
11,368 260
(7,761 189)
344 816
373 113
442 408
264,400
100
603 000
(1,419 600)
167,423
316,667
747 064
626 049
626 049
611 601
123 690
239 593
(115 903)
(109 065)
789 763
583 066
789 763
372 829
(795 562)
21,458
21,457
774,105
598 724
126 013)
(14 029 877)
(14 029 877)
(35 075)
(35,075)
090 938)
(12 938 939)
Note: Negative amounts indicate benefit to ratepayers
U:lkhe,,;nl;pceO710ISlaff Ca"'ITRUE UP 5/9/2007 KDH
2006
DEC
021 056
507
559 787)
346 182
274 108
72,074
213 726)
120 999
815,731
806
139 155
21,860 906
(17,822,923)
213,726
949 948
726 608
273 100
700
841 100
(3,443 800)
167,423
316 667
347,464
602,484
602 484
591 644
218 089
483 863
(265 774)
(250 093)
901 338
372 829
901 338
274 166
(774 105)
932
912
733 193
540 973
282 021 )
(12 938 939)
(12 938 939)
(32 347)
(32,347)
249 674)
(11 689,265)
2007
JAN
096,401
507
748 677)
382 283
265 091
117,192
973,513)
500
852
253 901
530 042
841 568
(20 964 875)
973 513
807,475
453 508
272 200
100
387 500
889 800)
167 423
316 667
125 264
682 211
682 211
659 164
401 300
036,410
(635,110)
(597 639)
810 203
274 166
810 203
084 369
(733 193)
685
685
672 508
31,411 862
400,463)
(11 689,265)
(11 689 265)
(29 223)
(29 223)
371 240)
(10 318,026)
2007
FEB
032 663
507
588 886)
106 621
092 645
976
(235 356)
173 888
9,431 155
151,429
11,446
930 081
(14 089 689)
235 356
372 954
372,808
257 500
300
000
776 100)
167 423
316 667
(184 736)
557 690
557 690
6,400 608
133 362
957 595
(824 233)
(775 603)
213 891
084 369
213 891
40,298 260
(672,508)
211
211
592 297
705 963
298,217)
(10 318 026)
(10 318,026)
(25 795)
(25 795)
272 422)
045 604)
2007
MAR
971 533
507
(2,435,633)
089 553
078 723
830
(182 377)
114 227
736 944
939
609,723
322 075
(21 263 175)
182 377
(562 644)
282,408
273 600
800
800
155 400)
167 423
316
(624 036)
392
392
993
117 273
307 604
(190 331)
(179 101)
308 524
298,260
308 524
606 784
(592 297)
100 746
100 797
491 500
115 284
127 125)
045 604)
TOTALS
586 872
(19 704 842)
372 653
662 171
710,482
(11 964 517)
500
804 603
110 532 921
123 370
058 537
224 881 906
(205 529 286)
964 517
126 970 034
138 364
257 200
194 300
11,842 800
(64 162 300)
004 538
900 002
374 900
80,595 134
712,488
882 646
154 513
320 147
059 005
738 858)
636 265)
608 333)
972)
606 784
606 784
647
556 147
(491 500)
115 284
834 824)
513,298
(39 513,704)
(333 015)
(15 333,421)045 604)
(22 614)
(22 614) (442 496)
(1,104 511) (7,392 328)
(7,941 093) (7 941 093)
Attachment D
Case No. IPC-07-
Staff Comments
5/14/07 Page 2 of2
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CERTIFICATE OF SERVICE
HEREBY CERTIFY THAT I HAVE THIS 14TH DAY OF MAY 2007
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. IPC-07-, BY MAILING A COpy THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
BARTON L KLINE
LISA D NORDSTROM
IDAHO POWER CaMP ANY
PO BOX 70
BOISE ID 83707-0070
MAIL: bkline(~jdahopower.com
InordstromcmidaJill)20Wer. com
JOHN R GALE
GREGORY W SAID
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
MAIL: rgale~idahopower.com
gsaidcmidahopower.com
TARY
CERTIFICATE OF SERVICE