20101116McDougal Reb, Exhibits.pdf

REC J
inJ6 NOV i 6 AM fO: l 9
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF ROCKY
MOUNTAIN POWER FOR
APPROVAL OF CHANGES TO ITS
ELECTRIC SERVICE SCHEDULES
AND A PRICE INCREASE OF $27.7
MILLION, OR APPROXIMATELY
13.7 PERCENT
)
) CASE NO. PAC-E-10-07
)
) Rebuttal Testimony of Steven R. McDougal
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)
)
)
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-10-07
November 2010
1 Q.
2 A.
Please state your name and business address.
My name is Steven R. McDougal and my business address is 201 South Main,
3 Suite 2300, Salt Lake City, Utah, 8411 1.
4 Q.Are you the same Steven R. McDougal who submitted pre-filed direct
5 testimony in thi proceeding?
6 A. Yes.
7 Purpose and Summary of Testimony
8 Q.
9 A.
10
11
12 Q.
13 A.
14
15
16
17
18
19
20
21
22
23
What is the purpose of your rebuttal testimony in this proceeding?
The purpose of my testimony is to respond to adjustments proposed in the pre-
fied diect testimony fied by the intervening paries regardig the Company's
revenue requirement.
Please summarize your testimony.
My testimony explains and supports the Company's revise overall revenue
increase request of $24.9 millon. This is a reduction from the $27.7 request
included in the Company's original filing. My testiony and exhibits also
provide: (1) a detaled calculation of the $24.9 millon requested revenue
increase, including a sumar of the diferences between the $27.7 milion
request and the revised requested amount. The revised request includes the impact
of adjustments proposed by other paries that the Company has accepted; 2) the
Company's response to certain revenue requirement adjustments proposed by
intervening pares in ths case which the Company contests; and (3) updates to
the Company's case due to a change in bonus depreciation law. The Small
Business Jobs Act of 2010, which became law on September 27,2010, extended
McDougal, Di-Reb - 1
Rocky Mountain Power
1 50 percent bonus depreciation for qualing assets for one year (calendar year
2 2010). This update reduces the price increase in this rate case by approximtely
3 $1.8 millon. This adjustment was not included in the diect testimony of any of
4 the intervenors, but is being included in this rate case to accurately reflect this tax
5 law change occurng after the case was fied.
6 Required Revenue Increase
7 Q.
8
9 A.
10
11
12 Q.
13 A.
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15
16
17
18
19
20
What price increase is required to achieve the requested return on equity in
this case?
As shown on Page 1.0 of Exhibit No. 78, an overall price increase of $24.9
milion is required to produce the 10.6 percent retu on equity requested by the
Company.
Please describe the. calculation of the revised overall revenue increase.
The Company's revised revenue increase of $24.9 millon was calculated using
the same allocation methodology and factors included in the original fiing and
incorporates certin adjustments proposed by other paries. In support of the
revised calculation, Exhibit No. 79 shows a summar of the adjustments made to
the original revenue requirement requested by the Company. Exhibit No. 79 is a
revised Exhbit NO.2 from the Company's original filing with updated Tabs 1,2,
9 and 10 and includes a new Tab 11 contaning backup pages for each new
adjustment made to the Company's fiing.
McDougal, Di-Reb - 2
Rocky Mounta Power
1 Revenue Requirement Adjustments
2 Q.
3
4 A.
5
6
Is the Company incorporating any adjustments proposed by the intervening
parties into its revenue requiement calculation?
Yes. The Company has incorporated the following new adjustments, including
some proposed by intervening pares, into the Company's revenue requirement
calculation. Each is described fuher in my testimony.
(figues are in $1,OOO's)
Original Request
Rebuttal Adjustments
Cost of Debt and Preferred
11.1 Bridger Unit 2 Overhaul Liquidated Damages
11.2 Medicare Subsidy
11.3 Avian Settlement
11.4 Generation Overhaul Expense
11.5 Major Plant Additions - Plant in Service
11.6 Major Plant Additions - Tax Impact
11.7 Major Plant Additions.. Depreciation Expense
11.8 Major Plant Additions - Depreciation Resere
11.9 Net Power Costs
11.0 S02 Sales
Rebuttal Price Increae
7 Cost of Debt and Preferred
8 Q.
9 A.
10
11
Propo
Prce
Increase
$ 27,698
(127)
(2)
(5)
(10)
(82)
(226)
(1,784)
(45)
7
(274)
(280)
$ 24,870
Please summarize adjustments made to the cost of debt and preferred.
The revenue requirement model has been updated with the 5.88 percent for the
cost of debt and 5.42 percent for the cost of preferred as described in the
testiony of Company witness Mr. Bruce N. Wiliams.
McDougal, Di-Reb - 3
Rocky Mounta Power
1 Bridger Unit 2 Overhaul Liquidated Damages
2 Q.
3
4 A.
5
6
7
8 Q.
9 A.
10
11
12
13
14
15
16 Q.
17 A.
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19
20
21 Q.
22
23 A.
Please summarize IPUC staff witness Mr. Joe Leckie's proposed adjustment
related to an overhaul done on Bridger Unit #2 in 2009.
Mr. Leckie proposes that an adjustment be made to remove $240,497 total
company rate base from results, along with the corresponding depreciation
expense and reserve, in order to properly account for liquidated damges received
by the Company associated with an overhaul done on Bridger Unit #2 in 2009.
How has the Compàny accounted for those liquidated damages?
The Company and contractor agreed that $625,000 in liquidated damages would
be treated as a reduction to multiple Bridger Unit #1 overhaul projects in progress
for that contractor. In the Company's case, $264,254 was accounted for as a credit
against the Bridger Unit #1 Reheater project which was included in the
Company's Major Plant Additions Adjustment. The other projects that were also
allocated a portion of the liquidated damges were each less than the $5 mion
theshold for inclusion in ths case.
Has this adjustment been correctly reflected in IPUC's modeled position?
No. IPUC's adjustment removes the accumulated depreciation reserve from
PERC Account 11 1SP instead of PERC Account 108SP and the adjustment to the
accumulated depreciation reserve is a negative amount and should be a positive
amount to reflect removing a piece of the reserve.
Is the Company adopting the propos adjustment in its revenue
requiment computation?
Yes. The Company has correctly reflected ths adjustment in the rebutta position
McDougal, Di-Reb - 4
Rocky Mounta Power
1 as adjustment 11.1 of Exhibit No. 79.
2 Medicare Subsidy
3 Q.
4
5 A.
6
7
8
9
10
11
12
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14
15 Q.
16
17 A.
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19
20
Please summarize IPUC Staff's position regarding the Medicare Subsidy
regulatory asset.
IPUC Staff witness Ms. Cecily Vaughn proposes to reduce 2011 amortation
expense reflected in Adjustment 7.9 of my Exhibit NO.2 for the non-deductible
post-retirement prescription drg coverage ("Medicare Subsidy") regulatory asset,
approved in Case No. PAC-E-1O-04.
In this case, the Company originally requested recovery of the Medicare
Subsidy regulatory asset using December 31, 2009, data; however, once the
Patient Protection and Affordable Care Act ("PPCA") was enacted March 30,
2010, a revision to the regulatory asset balance was necssar. The result is a
reduction to the regulatory asset balance of $19,996 or an equivalent reduction in
yearly amortization expense of $4,999.
Doe the Company agree with IPUC staffs proposed adjustment to Medicare
Subsidy?
Yes. As stated by Ms. Vaughn, the Company provided a revised amortation
schedule reflectig accounting informtion though March 31, 2010; therefore,
the Company has no objection to ths adjustment. This adjustment is included as
adjustment 11.2 in Exhibit No. 79.
McDougal, Di-Reb - 5
Rocky Mountan Power
1 Avian Settlement
2 Q.
3
4 A.
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6
7
8
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21 Q.
22 A.
23
Please explain the adjustments being proposed for the Avian Settlement
Agreement.
IPUC witness Ms. Vaughn and PUC witness Mr. OregMeyer both propose to
remove a $500,000 entry made though Adjustment 4.17 - Avian Settlement, for
Operation and Maintenance (O&M) expense. As shown on page 4.17.1, the
expense was recorded on December 31,2008, and is not included in the rate case.
This adjustment is backing out the Apri 30, 2009, reversing adjustment. Ms.
Vaughn argues for disallowance because this is a non-recurng expense. Mr.
Meyer proposes removal under the premise that these are included in the balances
used to calculate a normalized level of Injuries and Damages though the
Adjustment 4.14 - Insurance Expense. He argues that allowing the Company's
adjustment would represent a double recovery of costs if using a cash basis
method for Injures and Damages, or an overstatement of costs if using the
Company fied 3-year average accrual method. The proposed adjustments result
in a reduction to revenue requirement of $26,961.
Additionally, Ms. Vaughn maes an adjustment to remove rate base
related to transmission improvement projects to be completed as par of the Avian
Protection Plan because it falls below the $5,000,000 theshold for 2010 pro-
form plant additions.
Pleas explai the Company's position on the propoed adjusments.
The Company opposes the O&M adjustments. As described below, both
adjustments are flawed. They are reversing costs which are not in the rate case.
McDougal, Di-Reb - 6
Rocky Mountan Power
1
2
3 Q.
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5 A.
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20 Q.
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22 A.
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However, the Company is accepting Ms. Vaughn's rate base adjustment because
it falls below the $5 millon threshold for capital projects in this case.
Please explain the nature of the costs included in the $500,000 entry in the
Avian Settlement Adjustment.
In December 2008, the Company recorded an accrual for $500,000 representing
the best available estimate for restitution costs related to the Avian Settlement
Agreement. In general, the purpose of these restitution costs is to support efforts
in research, population monitoring, and conservation though improvements to the
design and constrction of avian-safe power lines. However, at the time of the
initial accrual the exact amount of restitution funds and purpose was unkown and
the estimate was thus recorded to FERC account 925 - Injuries & Damages. In
April 2009, the initial December 2008 accrual was reversed by credit to account
925.
The $500,000 entr included in Adjustment 4.17 is required to offset the
reversal of a credit. Absent this adjustment, there would be a mismatch in
unadjusted results which only reflects a reversal of costs that ar not included in
the case. The purpose of the Avian adjustment is to remove the impact of a prior
period restitution estiate, not to recover an incremental level of Injures &
Damages expense.
What is the basis for Ms. Vaughn's adjustment to remove the $500,00
adjustment to O&M?
Ms. Vaughn argues this is a non-reurg expense. The purose of ths
adjustment is not to recover a non-recurrg incremental charge for Injures &
McDougal, Di-Reb-7
Rocky Mountan Power
1
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3
4
5
6
7 Q.
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9 A.
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22 Q.
23 A.
Damages but to correct and completely remove the effect of a prior period accrual
by excluding its related reversal from results. As shown on page 4.17.1 of Exhibit
No.2, an entr was made on December 31, 2008, for $500,000 for the Avian
settement. This entr was before the historical period, and is not included in the
rate case. Page 4.17.1 also shows the reversal of the $500,000 accrual which
occurred on April 31, 2009.
Do you agree with Mr. Meyer's argument to remove the $500,000 credt
adjustment to O&M?
No. Mr. Meyer claims the Company's adjustment is to increase the level of
expense for Injures and Damages by reversing an Apri 2009 accounting entr.
He fuer states this would be in addition to the normization of Injuries and
Damges expense done though adjustment 4.14 - Insurance Expense. Mr. Meyer
argues that by using either his proposed method of cash basis normalization or the
accrual basis method fied by the Company, the $500,000 expense would be over-
recovered. This claim is flawed for two reasons. Firt, for the reasons stated
above, the Company is not attempting to increase the Injures and Damages level,
but only to correct the paral effect on a restitution accrual. Second, Mr. Meyer
contends this amount is aleady included in the Injures and Damages balances
included in PUC 74 and simultaneously in Adjustment 4.14 - Insurce Expense.
Ths clai is also mistaen because the Avian costs are not included in
Adjustment 4.14.
Please explain the impact of Ms. Vaughn's proposed adjustment to rate base.
From Ms. Vaughn's testiony, the amount of IPUC' s rate base adjustment is
McDougal, Di-Reb - 8
Rocky Mounta Power
1 unclear. Page 5 states it would be a reduction of $6,339, and page 15 states it
2 would be a reduction of $8,194, presumably takig depreciation expense into
3 account. Because IPUC workpapers remove all rate base components, the
4 Company assumes the correct impact would be a reduction to Idao revenue
5 requirement of $8,764.
6 Q.Please explain the Company's proposed adjustment.
7 A.The Company does not oppose the proposed rate base adjustment on the basis that
8 if falls below the $5 millon theshold for 2010 pro-forma plant additions.
9 However, this holds no relevance when considering the project's usefulness.
10 Therefore, the Company agrees to make this adjustment in the curent case, but
11 reserves the right to request recovery of these costs in its next general rate case
12 proceeding. The Company bears a responsibilty to operate, design and constrct
13 avian-safe power lines, and the capital projects are designed to do so. This
14 adjustment is included as Adjustment 11.3 in Exhbit No. 79.
15 Generation Overhaul Expense
16 Q.Please describe the proposed adjustments to generation overhaul expense.
17 A.Mr. Meyer makes two adjustments to the Company' s generation overhaul
18 adjustment. First, he rejects restating historical amounts to curent dollars prior to
19 averaging. Second, he proposes changing the four year average for new
20 generation units.
21 Q.Do the Company agree with the adjustments made to generation overhaul
22 expense?
23 A.No. The Company believes that overhaul expenses should be restated to curent
McDougal, Di-Reb - 9
Rocky Mountain Power
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2 Q.
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4 A.
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11 Q.
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13 A.
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dollars prior to averaging.
Why doesn't the Compay agree with the change in the four year average for
new generation unts?
Mr. Meyer proposes to change the averaging method for the thee newer plants -
Curant Creek, Lake Side, and Chehalis - using a four-year average between 2007
and 2010. It is unreasonable to shift the four-year average of these plants to 2007
though 2010, considering Chehalis was first put into service in September 2008.
The Company's adjustment uses the actual costs for the first four full years plants
are in-service when available. When the plants have not been online for four
years, the Company uses the budget for the first four years of operation.
Does the Company agree with the adjustment not allowig the Company to
restate overhaul expenses to current dollar prior to escation?
No. The Company believes that overhaul expenses should be restated to curent
dollars prior to averaging and does not agree with Mr. Meyer's adjustment. The
Company continues to support the use of Global Insight indices to state overhauls
in curnt dollars prior to calculating the four-year average. Averages are
intended to reduce year-to-year varances in expense, but not adjust for the time
value of money and the issue of inflation, as the value of the dollar in the test
period wil be less than the value of the dollar in historical years. Company
incured expenses four years ago cost more in test year dollars to pay the same
expense. However, the Company is willing to pursue discussions with pares on
this issue to brig more clarty to the Company's position and, therefore, for ths
case only, the Company is removing the generation overhaul escalation, and
McDougal, Di-Reb - 10
Rocky Mountan Power
1 reserves its right to address this issue in the future with the Commssion. This
2 adjustment is included as Adjustment 11.4 in Exhibit No. 79.
3 Major Plant Additions
4 Q.
5
6 A.
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9
10 Q.
11 A.
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14
15 Q.
16
17 A.
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19
20
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22
Please describe Mr. Leckie's proposed adjustment to the major plant
additions included in the Company's filing.
Mr. Leckie proposes that an adjustment be made to remove $34 milion of total
company rate base from results, along with the corresponding depreciation
expense, to reflect updated project forecasts and in-servce dates that were
supplied by the Company.
Has this adjustment been correctly reflected in IPUC's modeled position?
No. IPUC's adjustment removes capita from a trnsmission and intagible
PERC account, instead of the PERC account where the capital was originally
included in the adjustment. Additionally, the corresponding accumulated
depreciation reserve adjustment has not been made in IPUC's modeled position.
Is the Company adopting the proposed adjustment in its revenue
requirement computation?
Yes. The Company is adopting this adjustment and has correctly reflected all
pieces of ths adjustment in the rebuttal position. The corrected adjustment is
included as Adjustments 11.5 through 11.8 in Exhibit No. 79 to reflect the
updted plant in service (Adjustment 11.5), deferred income taes (Adjustment
11.6), depreiation expense (Adjustment 11.7), and accumulated depreciation
reserve (Adjustment 11.8).
McDougal, Di-Reb - 11
Rocky Mountan Power
1 Q.Does Adjustment 11.6 include any change to taxes, other than updating for
2 the plant addition changes included in Adjustment 11.5?
3 A.Yes. In addition to updating for the change in major plant additions included in
4 Adjustment 11.5, Adjustment 11.6 also updates this case for a change in bonus
5 depreciation. The Small Business Jobs Act of 2010 became law on September 27,
6 2010. The Act extended 50 percent bonus depreciation for qualifying assets for
7 one year (calendar year 2010). This update reduces the price increase in this rate
8 case by approxitely $1.8 millon. This adjustment was not included in the
9 diect testimony of any of the intervenors, but is being included in this rate case to
10 accurately reflect this tax law change occurng after the case was fied.
11 Net Power Costs
12 Q.Have the net power costs been updated as part of the rebuttal filing?
13 A.Yes. As described in the testimony of Dr. Hui Shu, the Company has updated the
14 net power costs included in the case. These updates are incorporated into the
15 requested price increase as Adjustment 11.9 of Exhibit No. 79.
16 S02 Emission Allowance Revenues
17 Q.Please desribe witness Mr. Meyer's proposed adjustment related to S02
18 emision allowance sales revenues.
19 A.Mr. Meyer proposes that past revenues from the sales of S02 emission
20 allowances be amorted over five years instead of the 15-year amortzation
21 schedule use by the Company in the intial fiing.
McDougal, Di-Reb - 12
Rocky Mountai Power
1 Q.
2
3 A.
4
5
6
7
8
9
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11
12 Q.
13 A.
14
15 Q.
16
17
18 A.
19
20
Does the Company disagree with Mr. Meyer's adjustment to the
amortization of S02 allowances saes?
Yes. The Company agrees to shorten the amortization from 15 to 5 years;
however, Mr. Meyer's adjustment fails to take into account the impacts of the
adjustment to both rate base and taxes. The amortized sales are treated as a credit
to rate base. By excluding sales the rate base credt should also be reduced. Al
revenues associated with new sales of S02 credits are given to customers in the
year they are received as par of the Company's ECAM filings. The Company
agrees that a 5-year amortzation period flows back the revenues associated with
prior transactions to customers in a timelier manner and help to reduce the
proposed rate increase in this proceeding.
What is the impact of.Mr. Meyer's adjustment when correctly calculated?
Correctly calculating the adjustment reduces the Idao-allocated revenue
requirement by $280,220.
Has an adjustment associated with the amortization period of S02 emision
alowance sales revenues been reflected in your revised revenue
requirement?
Yes. Adjustment 11.10 of Exhbit No. 79 reflects the impact of changing the
amortzation period associated with S02 emission allowance revenues from 15
year to 5 years.
McDougal, Di-Reb - 13
Rocky Mountan Power
1 Contested Adjustments
2 Q.
3
4 A.
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Are there adjustments to revenue requirement proposed by other paries
that the Company is not accepting?
Yes. I wil address adjustments proposed by varous pares related to:
. Cash working capital
. Post test year rate base additions
. Pension expense
. Injures and damages expense
. Affiliate management fees
. Outside services expense
. Uncollectible accounts expense
. Deferral of coal overburden strpping expense
. Imputed sublease revenue
. Property tax expense
. Residential retal revenue
. Jurisdictional load for allocations
. Allocation of the Monsanto special contract
. Allocation of the Idao Irgation Load Control Program
Other Company witnesses wil also address issues raised by other pares which I
have not incorporated into the Company's proposed revenue requirement,
including:
. Residential load normlization and forecaste irgation load
. Jurisdictional line losses
. General wage increases
. Incentive compensation
. Pension expense
. Supplementa executive retiement plan expense
. Fuel stock
. Incremental generation O&M expense
. Dunlap I wind plant capita costs
. Populus to Termal trsmission line
. Unbiled usage
McDougal, Di-Reb - 14
Rocky Mounta Power
1 Cash Working Capital
2 Q.
3
4
5 A.
6 Q.
7 A.
8
9
10
11
12
13
14 Q.
15
16 A.
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18
19
20 Q.
21
22 A.
23
Mr. Meyer proposes to disallow $961,459 of other working capital and $2.1
million of cash working capital ("CWC"). Do you agree with these
adjustments?
No.
Does Mr. Meyer provide an explanation for these adjustments?
Yes. Mr. Meyer asserts that the $961,459 of other working capital is merely
another method to determne a working capital allowance and the Company is
attempting to double-recover such an allowance. Mr. Meyer clais these other
working capital components are considered in a lead-lag study and should not be
separately included in rate base. Mr. Meyer broadly states that, "It has been my
experience that electric utilties generally have a negative CWC allowance when a
properly calculated lead-lag study is performed."
Did Mr. Meyer base his conclusion on an anaysis of the Company's lead-lag
study?
No. Mr. Meyer made his statements without reviewing the lead-lag study, which
he did not request in time to receive prior to filng his testimony. He states that he
may update his testimony after reviewing the lead-lag study since he had not
aleady done so.
When did Mr. Meyer submit data requests asking for the Company's lead-
lag study?
On October 6,2010, PUC submittd Data Request 108 asking for the lead-lag
study used in the 2008 rate case. Then, on October 8, 2010, PUC submitt Data
McDougal, Di-Reb - 15
Rocky Mountain Power
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7 Q.
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9 A.
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17 Q.
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19 A.
20
Request 112, asking for the 2007 lead-lag study referenced in Steve McDougal's
direct testimony along with all supportng work papers, and Data Request 113
asking for any additional work papers supporting the Company's cash workig
capital in the curent case. All responses were provided according to the pre-
determned procedural schedule, but Mr. Meyer did not request the study until too
late to review prior to filng his testimony on October 14, 2010.
Has the Company relied on a properly calculated lead-lag study to determine
cash working capital in this case?
Yes. The Company used a lead-lag study based on 2007 data to calculate Idaho's
cash working capita in this case. The Company updates its lead-lag study
approximately every five years or if there are significant changes in revenue
collection or expense remittance policy that would warant a new study. There
have been no significant changes since the 2007 study. The Company's previous
general rate cases in Idao have calculated working capita in the same manner as
included in this case. The 2007 lead lag study was included in the Company's
last Idaho general rate case, Case No. PAC-E-08-07.
Has th study been used to calculate CWC in any other ofPacifiCorp's
juriictions?
Yes. It has been used for rate settg puroses in Uta, Oregon, Wyoming and
Caliorna.
McDougal, Di-Reb - 16
Rocky Mountan Power
1 Q.Do you agree with Mr. Meyer's asrtion that including other working
2 capital is merely another method to determine a working capita allowance,
3 and that the Company is attempting to double-recover that allowance?
4 A.No. Mr. Meyer made these assertions without ever reviewing the Company's
5 lead-lag study. The assets and liabilties underlying the other working capital
6 balances in this case, and their related business transactions, are not èonsidered in
7 the Company's lead-lag study. The specific assets and liabilties he refers to are
8 other cash working capital items in accounts 135, Working Funds; 141, Notes
9 Receivable; 232, Accounts Payable, related to employee benefits; 253.3, Other
10 Miscellaneous Deferred Credits; and 254.105, Asset Retirement Obligation
11 Regulatory Liabilties, none of which are within the scope of the lead-lag study.
12 Consequently, there is no double-reovery of working capital and ths adjustment
13 is inappropriate.
14 Post Test-Year Rate Basé Additions
15 Q.Pleas describe Mr. Meyer's proposed adjustment to post-tet year rate base.
16 A.Mr. Meyer proposes an adjustment to remove approximately $665.8 milion of
J 7 total company rate base and $6.9 millon total company depreciation expense. Of
18 Mr. Meyer's total adjustment, $442.8 millon is due to increasing the accumulated
19 depreciation reserve and the remaining $223 millon is related to his estimate
20 impact on accumulated deferred income taes based on incorrect assumptions
21 regarding the calculation of the Company's test year in ths case. In his
22 adjustment, Mr. Meyer reflects additional accumulated depreciation beyond the
23 historical test year and uses rough estimates to compute the impact on
McDougal, Di-Reb - 17
Rocky Mounta Power
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5 A.
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accumulated deferred income taxes. Mr. Meyer also estimates pro form
retirements to calculate the impact those retirements wil have on depreciation
expense.
Do you agree with Mr. Meyer's proposed adjustment?
No. This case is based on a historical test period with limited adjustments
reaching out twelve months beyond December 31,2009. The test period in this
case is based on traditional rate makng conventions relied on in Idaho and is not
intended to be a full scale roll-forward into 2010. The Company has only
included capital projects over $5 millon that wil be used and useful by
December 31, 2010. Accumulated depreciation for these capital additions is
included as an offset based on the first full year of depreciation expense. Capita
projects below the $5 milion theshold or projects that are of a routine nature (i.e.
feeder improvements, distribution pole replacement, battery bank replacement,
etc.) are simply left out of the Company's case. The Company continues to place
hundreds of millons of dollars wort of these capital projects into service each
year. If the Company had included all budgeted capital additions in its original
filg, total company electrc plant in service would have increase by over $530
milion and would more than offset Mr. Meyer's additional accumulated
depreciation. Mr. Meyer's argument that "one must properly consider all
increases in gross plant in post-test year periods, along with all increases in
accumulated depreciation reserve" ignores the test period convention and the
limited natue of the Company's pro forma adjustments.
McDougal, Di-Reb - 18
Rocky Mounta Power
1 Q.Has any other pary in this proceeding addressed the Company's proposed
2 test period convention in this case?
3 A.Yes. Commssion staff witness Mr. Randy Lobb mentions the Company's test
4 period on page 3 of his diect testiony. Mr. Lobb states, "Staff accepts the
5 Company's proposed historic test year of Januar 1,2009 though December 31,
6 2009 with reasonable pro form adjustments through December 31,2010."
7 Injuries and Damages
8 Q.
9
10 A.
11
12
13
14
15
16
17
18
19
20 Q.
21 A.
22
23
Please describe the adjustments to injuries and damages ("I&D") expense
propose by PUC witness Mr. Meyer and IPUC witness Mr. Donn English.
Mr. Meyer proposes that I&D expense be based on actual claims paid less
insurance reimbUrsements (i.e. cash method) averaged over a the year period
(2007-2009). Mr. Meyer points out that by basing I&D expense on the cash
approach, ratepayers are only required to pay the actual cost associated with I&D
claims.
Mr. English proposes that I&D expense be based on expense (i.e. accrual
method) for calendar year 2009 only. Mr. English points out that the 2009 level is
the lowest expensed over the thee year period and that the amount expensed to
PERC account 925 has been trending downward. He attrbutes this trend to safety
measures undertaken by the Company durg 2008 and 2009.
Are there any errors in Mr. Meyer's calculations which should be corrcted?
Yes. In Mr. Meyer's cash basis calculation he includes actual claims paid but
mistaenly includes the insurance reeivable on an accrual basis, creating a
mismatch within his own adjustment. The table below shows the correct
McDougal, Di-Reb - 19
Rocky Mounta Power
1 calculation of a thee year average under each method, accrual and cash basis.
2 Mr. Meyer's inconsistency is highlighted with the dashed outlne.
I Injuries and Damages Accrual I Cash t I Variance I
Claims CY 2007 10,124,688 .'7,360,133 .(2,764,555)
Clais CY 2008 .
6,052,960 ~(2,447,373)8,500,333 .
Clais CY 2009 4,492,982 ~5,506,676 ~1,013,694
Total Claims $ .23,118,003 L $18,919,769..$(4,198,234)._._._._...
Insurce Receipts CY 2007
,._._._._.,
(4,717,560)i 4,717,560 iInsurace Receipts CY 2008 5,340,408 .2,795,245 (2,545,163)
Insurance Receipts CY 2009 .2,615,133 ~2,833,590 218,457
Total Insurance Receipts l$12,673,101 ,. $5,628,835 $(7,04,266). _. _._. _...
Total Claims Net of Insurce $10,44,902 $13,290,934 $2,846,032
3. Year Average $3,481,634 $4,430,311 $948,677
Idaho SO Allocation %5.392%5.392%5.392%
Idaho Allocated $187,730 $238,882 $51,153
3
4
5
6
7
8 Q.
9
10 A.
11
12
13
14
15
16
The Company's filing is based on the thee year average of accrued expenses net
of accrued receivables (the 'Accrual' column above). Correctly calculating the
three year average using a cash basis as proposed by Mr. Meyer would increase
the Company's case by $948,677 on a total Company basis and $51,153 on an
Idaho allocated basis.
Mr. Meyer argues that cash basis is needed so that rates are not set based on
estimates of future claim that may not materialie. Do you agree?
No. The Company only records an accrual (reserve) for a specific claim if there is
a liabilty to the Company, a 70 percent likelihood of a payout probabilty, and a
documentable amount that can be used as justification for the reserve amount.
Once a claim is presented to the Company, an internal analysis is conducted by a
reserve commttee to determne the effect the clai may have on the Company.
This reserving and establishing of an accrual is governed by F AS 5 accounting
rules and Sarbanes-Oxley legislation. In addition, if the amount expected to be
McDougal, Di-Reb - 20
Rocky Mountain Power
1
2
3 Q.
4 A.
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
paid out is subsequently changed, the adjustment is captured in the net insurance
expense.
Do you agree with the adjustment to I&D expense proposd by Mr. Englih?
No. Mr. English proposes to include I&D expense using just the calendar year
2009 results. His proposal is based on the fact that I&D expense in 2009 is the
lowest over the last three years. Whe I agree that the expense booked to PERC
account 925 has declined, I&D expense wil natualy vary year to year due to the
types of underlying claims. Expenses booked tothis account include the cost for
claims from events in which there is damge or bodily injur to a thir par.
This account does include expenses incurred as the result of auto accidents, other
accidents and daages where a degree of employee negligence is involved,
however, the majority of the expenses recorded as injur and damages are the
result of events outside the diect benefit of the recent safety measures mentioned
by Mr. English. These other types of events include, but are not limited to,
electrcal contact with power lines and equipment by the public, constrction
excavations of power lines and equipment by third paries, damages from fires
caused by faulty transformers and other types of equipment, business interrption
from power outages and varous other types.
As Mr. English points out in his testimony, the Company has recently
improved its safety penormce, but claims wil inevitably continue and the level
of expense wil certy var over time. One of the major safety improvements
at the Company has been related to preventable vehicle accidents. However, as
shown on page 4.14.1 of Exhibit No.2, auto daages account for less than 10
McDougal, Di-Reb - 21
Rocky Mountan Power
1
2
3
4
5
6 Q.
7
8 A.
9
10
11
12
13
14
15 Q.
16
17 A.
18
19
20
21
22
23
percent of claims paid. Contrar to Mr. English's implication, the Company's
improved safety is not the main reason for the low I&D clais in 2009. These
amounts tend to be unpredictable in natue. The purose of the thee year average
is to provide a smoothing of this expense over time because of the varability and
ensure recovery of prudent costs while avoiding setting rates on high or low years.
Does Mr. English propose using an average to normalize other expenses in
this case?
Yes. Mr. English proposes using a five year average of cash contrbutions to the
Company's pension plan to set the level of pension expense in ths case. His
argument there is just the opposite of his support for I&D expense - the base year
included in the Company's case is too high and that an average should be used to
reduce the amount included in rates. It appears Mr. English is tring to cherr-
pick actual, a historical average or a forecast average depending on which gives a
lower result.
What treatment does the Company recommend for injuries and damages
expense?
The Company continues to recommend using a thee year average of the net
injures and damages expense on an accrual basis, and respectflly requests the
Commssion make a determnation that a thee year average be consistently
applied in ths and futue rate cases. The Commssion should reject the cash
method proposed by Mr. Meyer and also the method proposed by Mr. English
which uses only the base period (CY 2009) experience to determe the I&D
expense level to be recovered in rates.
McDougal, Di-Reb - 22
Rocky Mountan Power
1 Pension Expense
2 Q.
3
4 A.
5 Q.
6
7 A.
8
9
10
11
12
Does the Company recommend any change to the Company's filed position
to calculate cash basis pension expense?
No.
Please describe the $19.1 milion adjustment referenced in Mr. Williams'
testimony.
As described in the testimony of Mr. Wiliam, the Company does not accept Mr.
English's proposed adjustment, and proposes to continue on a cash basis as
included in Exhibit 2, page 4.13. However, if the Commssion proposes to use an
average, it should use a three-year historical average, which would result in an
adjustment of $19.1 millon. The calculation of the $ 19.1 millon is shown in the
table below.
McDougal, Di-Reb - 23
Rocky Mountan Power
1 Q.
2
3 A.
4
5 Q.
6 A.
7
8
9
10
11
Cash Contributions:
Original Company Filng $ 104,80,00
Three Year Historical Average
2008 Actual
2009 Actual
2010 Actual (1)
3 Year AlArage
$ 65,627,000
49,564,280
112,800,000
75,997,093
Case adjustment to change to a 3 year average
RemolA mines and joint wntures
Remow capitalization
Rate Case Adjustment - Total Company
Rate Case Adjustment - Idaho Allocated
28,802,907
(2,003,654)
(7,686,106)
$ 19,113,147
$ 1,03,623
(1) The case was filed using a preliminary estimate for 2010 pension contribution
of $104.8 milion. Actual contribution for 2010 is $112.8 milion.
Has the Company proposed to use a 3-year hitorical average to calculate
any other level of expense in this cae.
Yes. This is the same approach the Company recommends to calculate injures
and damges expense.
Is Mr. Englih's adjustment consistent with the test period used in thi cae?
No. Mr. English is only allowing a forecast beyond the known and measurable
period to be used for this one item. All other items are based on the historical test
period with known and measurable changes. Over the next several years the
Company is forecastig cost increases relate to plant-in-servce, medical
benefits, general inflation, etc. Whe using a five-year projected average
produces a decrease in pension costs, it is inconsistent with the test period used in
McDougal, Di-Reb - 24
Rocky Mounta Power
1 this case and is inappropriate.
2 This is also inconsistent with other adjustments proposed by the IPUC
3 staff. Staff is proposing to use a five-year historical average for propert taes,
4 and at the same time they are proposing to eliminate the the year average used
5 for injures and damages.
6 MidAmerican Energ Holdings Company ("MEHC") Management Fee
7 Q.
8
9 A.
10
11
12
13 Q.
14
15 A.
16
17
18
19
20 Q.
21
22 A.
23
Please describe the adjustments to the MEHC management fee proposed by
Mr. Meyer and Mr. English.
Mr. Meyer and Mr. English each propose to elimnate portons of the MEHC
management fee related to the incentive compensation. Mr. English also
recommends removing supplemental executive retirement plan ("SERP") costs
and Mr. Meyer recommends removing legislative expenses.
Do you agree that the costs of SERP and incentive compensation should be
removed from the MEHC management fee?
No. As explained in furher detail by Company witness Mr. Erich D. Wilson,
SERP and incentive compensation are individual components of total
compensation packages simiar to those provided to PacifiCorp employees.
Expenses related to SERP and incentive compensation are appropriately included
in regulated results.
Mr. Meyer also makes an adjustment to remove legislative costs from the
mangement fee. Do you agree with hi proposal?
No. I agree that costs strictly relate to the Company's legislative activity should
not be included in regulate results. However, contrar to Mr. Meyer's asserton,
McDougal, Di-Reb - 25
Rocky Mountan Power
1
2
3
4 Q.
5 A.
6
7
8
9
10
11
12 Q.
13 A.
14
15
16
17
18
19 Q.
20
21 A.
22
23
the Company has already capped the level of MEHC management fee expenses in
this case and excluded the legislative costs from results. Therefore, Mr. Meyer is
removing costs that are not included in the case.
Please further explain the cap on MEHC maagement fees.
In merger commtment 28, the Company commtted to hold customers haress
for costs that were previously assigned to affilates under the previous ownership.
This commtment would be satisfied if PacifiCorp demonstrates that corporate
allocations from MEHC to PacifCorp included in rates are limited to $7.3
milion. In general rate cases since the merger, the Company has limited the
MEHC management fee included in rates to $7.3 millon; in ths case it is shown
on page 4.8 of Exhibit NO.2 of my direct testimony.
Does Mr. Meyer consider this cap when makig his adjustment?
Mr. Meyer indicates that he considers the cap to be the upper limt for these
charges and that disallowances should be fuer reductions below the cap,
regardless of the actual underlying accounting. He indicates that since his
proposal to remove $2.1 millon (related to both incentive compensation and
legislative costs) is greater than the $1.1 mion reduction the Company made to
arve at the capped level, fuer adjustment is warnted.
Do you agree with Mr. Meyer's interpretation of the treatment for proposed
dilowances?
No. Mr. Meyer does not believe the Company has removed adequate costs from
the maagement fee biled to PacifiCorp because the case only shows a reduction
of $1.1 miion, but he fails to consider that a portion of the management fee
McDougal, Di-Reb - 26
Rocky Mountai Power
1
2
3
4
5
6
7
8
9
10
11 Q.
12
13 A.
14
15
16
biled to PacifiCorp was not booked above-the-line to begin with. The
Company's downward adjustment reduced the expenses booked above-the-line
from $8.4 millon to $7.3 millon. Durng 2009 MEHC biled PacifiCorp a tota
of $1 1.6 millon, includig costs related to legislative activities, incentive
compensation, SERP, and other charges. As shown in the table below, only $8.4
milion of the $11.6 millon biled was originally booked above-the-line, and only
$7.3 milion was included in the case.
MEHC original invoices
Remove charges not eligible for inclusion in expense in the fiing:
Amount capitalize
Legislative
Aicr costs exclude
LTIP
Eligible expenses
Cap per Commitment 28
Eligible expenses not included in fiing
Summar of amount included in Idaho GRC results
Amount charged to expense above the line in unadjusted results
Removed frm unadjusted results in original filing
Amount charged to expense in original rilg
$11,568,011
(206,427)
(330,636)
(708,780)
(2,889,093)
$7,433,076
7,300,00
$133,076
$8,353,029
(1,053,029)
$7,30,000
The Company's original accounting and fuher adjustment to limit the
MEHC fee in rates to $7.3 millon adequately satisfies the Company's obligation
to bear the cost of inappropriate charges.
Has the Company reazed benefits from MEHC management since the
acquisition of PacifiCorp?
Yes. The Company has benefitted and wil contiue to benefit from having
MEHC as its holdig company in several respects. Since MEHC acquired
PacifCorp, it has implemente cost cuttg strategies that have saved customers
milions of dollars. For example, it is no coincidence that labor costs either come
McDougal, Di-Reb - 27
Rocky Mountan Power
1 in lower or almost level with every rate case fied - even during periods when
2 medical costs were rising signifcantly from year to year. MEHC's safety policies
3 have made a positive difference in the Company's safety record, which also
4 translates into dollars saved. Corporate functions that are performed by MEHC
5 on behalf of pacifiCorp also save customers money because PacifiCorp does not
6 have to perform those functions on its own. If MEHC were not performg those
7 functions, PacifiCorp would have to do so and may have to do it at a higher cost.
8 Also, because the Company's ownership changed from a publicly held company
9 to a privately held utilty, there are no shareholders' services costs that must be
10 paid. Notably, before MEHC ownership, the Company paid $15 millon to its
11 prior owners in management costs. In keeping with its cost cutting philosophies,
12 when MEHC acquired the Company, MEHC agreed that ratepayers need only pay
13 $7.3 millon of the $15 milion typically paid to the prior owner. In sum, the
14 Company has shown that as a result of MEHC' s phiosophy of runng a
15 streamlned company, millons of dollars have been saved to the benefit of the
16 Company, but most importntly, to the benefit of the Company's ratepayers.
17 Outside Services Expense
18 Q.Pleas summrize Mr. Meyer's proposed adjustment to outside servces
19 expense.
20 A.Mr. Meyer proposes to adjust the Company's outside services expense (PERC
21 account 923) to a four year historical average of years 2006 - 2009. Ths
22 adjustment would reduce revenue requirment by $327,080 on an Idao allocated
23 basis.
McDougal, Di-Reb - 28
Rocky Mounta Power
1 Q.
2
3 A.
4
5
6
7
8
9
10
11 Q.
12
13 A.
14
15 Q.
16
17
18 A.
19
20
21
22
Does Mr. Meyer provide adequate evidence to support his recommendation
for treating outside services expense differently than other O&M expenses?
No. Mr. Meyer's entire argument consists of a single sentence stating "the level
of expense incured in 2009 is the highest level of expense recorded by RMP
since 2006." 1 It is unclear why Mr. Meyer has singled out outside services for ths
treatment, and he provides no concrete explanation why this parcular O&M
account deserves historical average treatment while others do not. Over the same
period of time renewable energy credits ("RECs") have increased from $3.7
milion to over $90 millon in the test period in this case. The level of expense or
revenue change over time is, by itself, no reason to use an average.
Does Mr. Meyer challenge the prudence of any specific cost contained within
the outside services expens included in the test year?
No. He does not take issue with the prudence of any of the specific costs
contained within the base period outside service expense.
Do you believe that the level of outside services expense the Company
experienced in the 12 months ended December 31, 2009 represents a
reasonable, ongoing level of expense? Why?
Yes. I believe the level of outside services expense in the base period is
reasonable. Below is a table simiar to the one Mr. Meyer included in his diect
testiony, except this table includes fiscal year 2005 to ilustrate that the
fluctuations in this account are reasonable and do not warant the special
treatment proposed by Mr. Meyer.
lDit Testiony of Grg R. Meyer, Page 34. Line 1 - 2.
McDougal, Di-Reb - 29
Rocky Mounta Power
1 Q.
2
3 A.
4
5
6
7
8
9
10 Q.
11 A.
12
13
14
15
16
17
18
19
Outside Services ExpenseFY2006 1,542,476CY2006 1,067,814CY2007 580,987CY2008 670,661CY2009 1,209,260
4 yr avg $ 882,181
5 yr avg $ 1,014,240
What else concerns you with regards to Mr. Meyer's adjustment to outside
services?
Mr. Meyer proposes inconsistent adjustments to varous revenue requirement
categories included in the Company case. He recommends weather normalized
usage be adjusted to a five-year average, S02 revenues be adjusted to a five year
average, injures and dages expense be based on 3-year cash payments, and
uncollectible expense be adjusted to a four-year average. The only consistency the
Company finds among these adjustments is that they all decrease revenue
requirement.
Are there any other inconsistencies in Mr. Meyer's testimony?
Mr. Meyer is also very selective about which accounts he chooses to adjust. His
source for this adjustment to outside services was the Company's response to data
request PUC 64 which lists 2005 - 2009 O&M expense by FERC account. In
many accounts the 2009 test year expense is lower than the 4-year historical
average. However, no par propose an average methodology that would
increase test period revenue requirement. In addtion, he is even selective as to
which historical years to include in his average. Fiscal year 2006 outside services
expense was $1,542,476 so using a five-year average would have resulted in a
smaer adjustment to revenue requirment.
McDougal, Di-Reb - 30
Rocky Mounta Power
1 Q.Should selected accounts be adjusted to a four year historical average?
2 A.No. It is important to consider the overall level of O&M for reasonableness
3 instead of isolatig individual O&M accounts. In doing so, there wil always be
4 accounts that go up from a thee, four or five year average and accounts that go
5 down. Mr. Meyer provides no arguments supporting why outside service expense
6 is unique, therefore it would be no more appropriate to adjust this account
7 downward than it would be to adjust other FERC accounts upward to a four year
8 average. Accepting Mr. Meyer's adjustment would be unfai and would not
9 provide the Company a reasonable opportnity to recover its costs of providing
10 service to customers.
11 Uncollectible Accounts
12 Q.Please briefly describe Mr. Meyer's proposed adjustment to uncollectible
13 expense.
14 A.Mr. Meyer proposes to use a historical 4-year average of uncollectible expense
15 (PERC account 904) from calendar years 2006 - 2009 to estimate the appropriate
16 level for the test period. LIsing this methodology Mr. Meyer's adjustment would
17 reduce revenue requirement by $68,807.
18 Q.What evidence does Mr. Meyer provide to support hi recommendation for
19 using a four-year hitorical average treatment?
20 A.Mr. Meyer argues that because 2009 uncollectible expense was at the highest
21 level since 2006 it should be adjusted. He also claims that the level of
22 uncollectible expense is not dictate by the level of revenues.
McDougal, Di-Reb - 31
Rocky Mountan Power
1 Q.
2
3 A.
4
5
6
7
8
9
10
11 Q.
12 A.
13
14
15
Is Mr. Meyer's proposed adjustment a reasonable method of determining the
Company's uncollectible accounts expense?
No. This is another example of an adjustment that isolates a single expense
account to produce a reduction to revenue requirement. As discussed above, Mr.
Meyer recommends special treatment for this account but does not provide
adequate support for his argument. His proposal to use an historical average to
determne the level in 2010 is both unreasonable and inappropriate. The
Company's test period is based on 2009 actual data adjusted for known and
measurable events, not a test period of average costs from 2006 to 2009 and only
when those averages decrease the revenue requirement.
Why is it inappropriate to use a four-year historical average methodology?
This method fails to account for conditions durng the rate effective period. The
Company has experienced a steady increase in uncollectible expense since 2008.
The char below shows Idaho uncollectible expense for the 2006 - 2009, the 12
months ended June 2010 and year to date Januar though October 2010.
McDougal, Di-Reb - 32
Rocky Mountan Power
i.......................................................................................................................................................................................................1¡ ¡L Idaho Uncollectible Expense ¡$700,000 T"'''.... ........._....._......."'-~--_..."'-'$S2,5S4
¡ Meyer's Proped $406,456
$500,000 'r'- ......._~~~_...._._- -S412.3... -
$400,000.1,....
$303,856
$300,000 't-"
$200000 .i......., ' I 'I $100,000' I¡ $0 .1...... llli'",:: 12 ME Dec 12 ME Dec 12 ME Dec 12 ME Dec 12 MEJun Jan _ Oct ¡l",l:,
2006 2007 2008 2009 2010 2010 ,
L....................................................................................................................................................................................................J
1 As shown in the table above, the averaging method produces a 2010
2 uncollectible expense level that is below the actual expense for the first 10 months
3 of 2010. Adopting Mr. Meyer's adjustment would result in under-recovery of the
4 Company's uncollectible expense.
5 Bridger Coal Stripping
6 Q.Please explain Ms. Vaughn's adjustment related to the coal strpping
7 deferral.
8 A.Ms. Vaughn proposes to reduce Idao revenue requirement by $6,133 by
9 removing deferred coal strpping costs from rate base. In Case No. PAC-E-09-08
10 the Company was authoried to defer in a regulatory asset the costs associated
11 with the removal of overburden and waste materials at the Bridger mie. Ms.
12 Vaugh argues that because the regulatory asset was created as a result of an
13 accountig procedural change, it would be inappropriate for the asset to accrue a
McDougal, Di-Reb - 33
Rocky Mounta Power
1
2
3
4 Q.
5 A.
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
caring charge. She also argues that because the Company did not request a
caring charge in its original application, it should not be included in rate base in
this case.
Do you agree with Ms. Vaughn's proposed adjustment?
No. Ms. Vaughn's adjustment unfairly penalizes the Company for an attempt to
reduce the disparty created by timing difference between incurng the strpping
costs and the time when the uncovered coal is actually extracted. As approved by
the Commssion, strpping costs are now deferred to a regulatory asset rather than
immediately included in fuel stock inventory and amortzation is matched with
coal extraction. Without the deferred accountig treatment, the Company is
requird to reflect strpping costs as varable production costs during the period
that the strpping costs are incurred, impacting the cost of the inventory produced
in that period. Under this accounting requirement, customers could pay for the
costs of uncovering coal well before it was extracted from the mine. Under the
former treatment, strpping costs would be included in fuel stock inventory in the
curent period and they would be included in rate base. The regulatory asset now
serves as a temporar holding place for these costs until coal is extracted and
included in fuel stock. There is no real change in the underlying business process,
and the Company should be allowed to include the regulatory asset in rate base
just as the costs would have been included in fuel stock prior to the approval of
deferrd accounting treatment.
McDougal, Di-Reb - 34
Rocky Mounta Power
1 Q.Why did the Company not originally request a carrying chare in Case No.
2 PA C-E-09-08?
3 A.The Company's application in that case did not address the ratemakng treatment
4 related to the change in accounting. Rather, it deferred rate makg considerations
5 to a subsequent general rate case. In its order the Commssion witheld its review
6 and judgment regarding the propriety of the deferred coal stripping costs unti the
7 Company requested recovery of such costs through rates.
8 Imputed Sublease Revenue
9 Q.Mr. English proposes to impute sublease revenue related to two below
10 market subleases to the Utah Sport Commission ("USC") and the Economic
11 Development Commission of Utah ("EDCU"). Do you agre with this
12 adjustment?
13 A.No. While I agree with the premise that Idao customers should not subsidie
14 these below market subleases, in fact, the impact is alady excluded from Idaho
15 alocated results in this case.
McDougal, Di-Reb - 35
Rocky Mountan Power
1 Q.
2 A.
3
4
5
6
7
8
9
10
11
12
13
14
Please further desribe the subleases in question.
As described by Mr. English, the Company sublets a portion of its office space in
the One Utah Center ("OUC") in Salt Lake City, Utah, to EDCU and USC at a
rate of $1 per month rent plus operating expenses. The rent subsidy is considered
a challenge grant to these organizations. Makng contrbutions to these entities by
absorbing these lease expenses is a key element to partering with economic
development organizations that, in effect, become an industrial customers' first
point of contact in the state. For accounting puroses, the Company's results of
operations initially include the total cost of the master lease at the OUC,
approximately $2.1 millon per year, allocated to all states on the System
Overhead ("SO") factor. Each month, the subsidized porton of the subleases to
EDCU and USC is reclassified from rent expense to donation expenses in FERC
account 930 and is situs assigned to Utah. The accounting for calenda year 2009
is shown in the table below:
Desription
OUCRent
Rent Subsidy to EDeU/SCU
FERC Account
931 - Rents
931 - Rents
Aloction Factor Tota CompanySO $ 2,141,496SO (157,072)
Net Rent Allocte to Idao $ 1,984,425
Rent Donation/Challenge Grant 930.2 - Mise General Expenses UT $157,072
15 In 2009, rent payments totaling $157,072 for these two subleases were
16 directly assigned to Uta, rendering Mr. English's adjustment imputing $142,069
17 of sublease revenue unnecessar. None of the net costs associated with the below
18 maret rate for these two subleases has been allocated to Idaho rate payers, so Mr.
19 English is removing a cost that is not included in the rate case.
McDougal, Di-Reb - 36
Rocky Mountain Power
1 Property Tax Expense
2 Q.
3 A.
4
5
6
7 Q.
8
9 A.
10
11
12
13
14
15
16
17
18
19
20
21 Q.
22
23 A.
Please describe the adjustment to property taxes proposed by Mr. English.
Mr. English states that the Company routinely and successfully appeals the
assessed value for the propert that is taxed by varous states, resultig in property
tax refunds. Mr. English reduces tota Company property tax expense in the case
by $288,125, the average annual refund for tax years 2005 though 2010.
Why doe Mr. English's adjustment improperly reflect property ta expense
for the test period in this case?
The adjustment proposed by Mr. English is not applicable to the test period in this
case because it incorrectly assumes that prior year tax appeals were completely
ineffective in resolving disagreements concerning the valuation methodologies
employed by state assessment personnel. and that the use of such methodologies
must be challenged again durng every futue assessment year. On the contr,
as tax appeals are pursued and such appeals result in the use of more favorable
valuation methodologies, the adjusted valuation methods are incorporated into the
models employed by the Company when estimating property tax expense for rate
case puroses. In other words, the beneficial effect of prior year appeal activity
was taken into account by the Company when estiting 2010 property tax
expense in the curent rate case. Makng an additional adjustment pertaing to
prior year appeals would effectively double count the benefit of such appeals.
How does the estimte included in the Company's cae compare to curent
expectations of propert tax expense in 2010?
As explaied to Mr. English during his onsite visit to Portland, actual propert tax
McDougal, Di-Reb - 37
Rocky Mountai Power
1 expense for 2010 is likely to be several millon dollars higher than the estiate
2 contained within the Company's case. If the Commssion were to conclude that
3 the adjustment proposed by Mr. English is waranted, then it should also make an
4 additional upward adjustment to recognize that the original estimate in the
5 Company's case is understated. The size of that upward adjustment to 2010
6 propert tax expense would substantially exceed the size of the downward
7 adjustment proposed by Mr. English.
8 Residential Revenue
9 Q.Do you agree with Mr. Meyer's proposal to use the historical 5-year average
10 kWh usage/per customer bil instead of temperature normalized sales?
11 A.No. As fuer detailed in Company witness Dr. Peter C. Eelkema's testimony,
12 Mr. Meyer provides no rationale for ignoring temperatue normlization for the
13 residential class, nor his choice to extend the period from a 2010 test year to a
14 historical 5-year average.
15 Q.Do you agree with Mr. Meyer's revenue requirement computation resulting
16 from the change in average residential use per bil?
17 A.No. Mr. Meyer has failed to properly account for the full effect of increasing
18 residential sales. First, his computation of the incremental net power cost is
19 incorrect. Second, he fails to account for the correspondig change to
20 jursdctional load (energy and peak) used for inter-jursdictional allocation.
21 Q.Pleas explai why you disagree with Mr. Meyer's calculation of net power
22 costs relate to incrementa saes.
23 A.There ar two problems with Mr. Meyer's calculation of the net power cost
McDougal, Di-Reb - 38
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impact of his adjustment. First, Mr. Meyer uses embedded rather than
incremental net power costs in his calculation. Second, Mr. Meyer incorrectly
calculates the Idaho's embedded net power cost.
To correctly calculate the net power cost impact related to incremental
revenues, Mr. Meyer needs to use a power cost dispatch model, or use an estimate
based on the market price of energy. He fails to use either of these methods, and
instead assumes that the incremental. cost of power is equal to the embedded cost
of power.
Mr. Meyer incorrectly calculated embedded net power costs. His
calculation relies on the Idaho allocated net power cost adjustment included on
Page 5.1 of Exhbit 2 and not the Idao allocated total net power costs included in
the case. Mr. Meyer's calculation results in Idaho net power costs of $65,023,822
rather than the correct amount of $69,234,037 as reflected on page 2.2 of Exhibit
2. Corrting Mr. Meyer's embedded net power cost approach, without changing
to an accurate incremental net power cost approach, reduces his adjustment by
$36,846.
Pleas explain the effect of including the change to loads at input based on
Mr. Meyer's proposed incremental sales.
Increasing sales by 21,075 MWh as proposed by Mr. Meyer results in an increase
to Idao system energy loads of 23,157 MW when grossed up for line losses,
and a correspondig increase of 32.7 MW to peak loads. This increase has an
impact on Idao jursdctional alocation factors, and increases Idaho-alocated
revenue requirement by $ 1,1 17,959. When offsettg ths increase in allocate
McDougal, Di-Reb - 39
Rocky Mounta Power
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3 Q.
4 A.
costs against Mr. Meyer's imputed revenue adjustment of $1,168,333 (using the
corrected net power cost amount), the net result is an adjustment for $50,374.
What is your recommendation regarding Mr. Meyer's proposed adjustment?
The Company recommends no change be made to residential revenues as Mr.
5 Meyer fails to provide any proven support to indicate the validity of ignorig
6 temperature normalized sales. Dr. Eelkema provides testimony on why the
7 Company's forecast is more accurate than the simplistic average used by Mr.
8 Meyer. Furtermore, the Company rejects Mr. Meyer's adjustment to revenues
9 due to the miscalculation of net power costs and his failure to look at incremental
10 costs, along with his failure to captue the effect on Idaho jursdictional factors by
11 having no incrementa adjustment to loads at inputs.
12 Jurisdictional Load for Allocation
13 Q.
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15 A.
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18
19 Q.
20 A.
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22
23
Do you agree with Mr. Anthony J. Yankel's contention that the Company's
has overestimated line losses in jurisdictional loads?
No. The Company's load measurements are consistent with prior filgs, and are
calculated in a simlar manner for all states. Mr. Yanel's proposal is not
consistent with prior filngs, and he does not make simiar adjustments to other
states, leadig to inconsistent allocation factors among states.
Pleas describe the method that the Company used to estiate line losses.
The Company has taken the total energy coming into jursdiction plus any
generation in jursdiction minus energy leaving the jursdiction. The Company
adjusts for losses resulting from moving Bridger generation to Goshen, Kiport,
and Bora. After subtracting Idao reta sales, the remainder is losses.
McDougal, Di-Reb - 40
Rocky Mounta Power
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Has the calculation of Idaho loads been described in any prior filings with
the Commission?
Yes. The testimony of Company witness Mr. David L. Taylor in Case No. PAC-
E-02-3 described the calculation of the Company's Revised Protocol allocation
factors. His testimony with regard to the calculation of the system peak states:
"Each State's hourly load consists of the Company owned generation
within that State, purchases or interchanges delivered into the State, plus
metered flows of energy into the State from other pars of the PacifCorp
system. From that measurement, metered energy flows out of the State
and deliveries to non-retail customers are deducted to arve at that State's
retailload".2
Peak and energy loads used for allocation puroses in this case have been
calculated consistent with the description above.
Are there losses included in the Company's estimate which are not associated
with Idaho retail sales?
Yes. There are losses associated with moving energy for wholesale sales. Idaho
rate payers benefit from these wholesale sales though reduced energy costs. The
curent case allocates approximately $47 mion in wholesale sales to Idao.3
There are some losses that occur as a result of power moving though Idaho;
however, ths occurs to a much lesser degree than Mr. Yanel iners because
losses resulting from moving Bridger generation to Goshen, Kiport, and Borah
are not included. Mr.Yankel's proposal ignores all losses associated with those
sales.
2 Idao Ca No. PAC-E-02-3, Dit testiony of David L. Taylor, page 12, lies 11-15.3 Rebtta Exibit 2. page 2.3, lie 111
McDougal, Di-Reb - 41
Rocky Mountan Power
1 Q.Mr. Yankel states on page 20 and 22 of his testimony that transmission losses
2 should be equally shared by all jurisdictions. Does each state use the
3 transmission system equally?
4 A.No. Because there is insufficient generation in Idaho to support Idaho customers'
5 load, generation must be brought in from other locations. This would utilize the
6 transmission system more than a load center that is located closer to generation.
7 Q.Doe Mr. Yankel's proposl treat all states consistently?
8 A.No. Mr. Yanel reduces Idaho's load, but does not make simiar adjustments to
9 all other states. Mr. Yankel assumes he does not need to adjust net power costs
10 because his irgation and allocation load adjustments basically offset. This is an
11 invalid assumption because, in addition to calculating Idaho load contrar to
12 Revised Protocol, he also calculates it inconsistently with other states.
13 Monsanto Special Contract Allocation
14 Q.Do you agree with Ms. Kathryn E. Iverson's assertion that a proper
15 jurisictional alocation study would reflect only Monsto's rir demands
16 for puroses of allocating costs?
17 A.No. Ms. Iverson bases her argument on the claim that the Company has not
18 planed for, or acquird resources, on the basis of Monsanto's non-firload.
19 Company witness Mr. Gregory N. Duvall provides rebutt testimony
20 demonstratig that Monsanto's claim is incorrect and that the Company does, in
21 fact, plan for Monsanto's load and is required to provide service to Monsanto for
22 the vast majority of the time. The cunt curment contract with Monsanto
23 lits the number of hours in a year the Company can interrpt servce to
McDougal, Di-Reb - 42
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Monsanto and has specific constraints regarng the amount of load that can be
curtailed at a given time. In order for Ms. Iverson's assertion to be tre the
Company would need the abilty to curil service to Monsanto at any time with
no limitation over the course of a year.
Have you reviewed Ms. Iverson's calculation of the impact on revenue
requirement in this case using her suggested 'non-firm' allocation approach?
Yes.
Do you agree with her calculation of a $12 millon reduction to the overall
price increase sought by the Company in this case?
No. Ifound two main issues with Ms. Iverson's calculation of the non-fir
allocation impact. First, because she claims the Company does not plan for
Monsanto's non-fir load, Ms. Iverson has removed 170.1 MW of demad from
all twelve monthy coincident peaks used to determe Idao's contrbution to the
system peak. In other words, Monsanto proposes to include only 9 out of 182
MW of Monsanto demand in the Idaho jursdictional coincident peak every
month. If Monsanto's load were to be excluded from the Idaho jursdictional peak
for a study of this natue, it should only be excluded from a lited number of
months, realistically representing the impact of the curaient on PacifiCorp' s
operations. Second, Ms. Iverson improperly removed retail revenue from
Monsanto based on avoided non-fi demad charges. In reality Monsanto wil
not avoid reaching its peak demad for an enti month as a result of PacifiCorp
curlment. Revenue should be removed based on cured energy at the non-
fir energy rate of 2.38 cents per kiowatt hour. Finally, Ms. Iverson's
McDougal, Di-Reb - 43
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adjustment does not remove the appropriate amount of revenues related to
interrptible demand changes. Ms. Iverson's representation of Monsanto
curailment, removing 170.1 MW from the Idao jurisdictional peak every month
and avoiding demad charges for every month of the year, is certnly fiction.
Why is it not realistic to remove 170.1 MW from eah of the monthly
jurisdictional peaks?
According to the terms of the Company's contract with Monsanto for 2010,
economic curlment of 67 MW is available for 850 hours and operating reserves
curailment of 95 MW'is available for 188 hours. After accounting for line losses
the total curlment is 170.1 MW. However, removing all 170.1 MW from each
month's coincident peaks is in appropriate for thee reasons:
. The total hours available for some type of curilent equate to 1038, less
than 12 percent of the hour in the year. For the remaing hours during
which Monsanto load is not curiled the Company must stad ready to
provide electric service to Monsanto.
. Pursuant to the contract, the Company can never actually curail all 170.1
MW at one tie. Curilent for operatig reserves is assigned to two
smaller furaces, with total load of 95 MW, and economic curailment is
assigned to one larger fuace with a load of 67 MW. If one of the
fuaces is already not operating either for maintenance or overhaul, the
Company can curail both remainig fuaces, but the total curent
would be less than the 170.1 MW. If one of the fuaces is aleady not.
operatig for economic curaiment, the Company can only cur one
McDougal, Di-Reb - 44
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additional fuace. Mr. Duvall explains how the Company's resource
planning is impacted by this limitation to avaiable curailment. This
means the maximum actual curailment is 116 MW out of the 170.1
proposed by Ms. Iverson.
. As shown on Tab 5 - Page 6 of Exhibit 49 sponsored by Company witness
Craig Paice, for eight out of twelve months durng the test period tota
Monsanto load at the coincident peak is actually less than 170.1 MW. It
would be entiely inappropriate to reduce Monsanto load below zero in a
given month.
Have you properly calculated the impact of Monsanto's proposal on the
Company's case?
Yes. I performed a calculation similar to the one proposed by Ms. Iverson, but
that also considers the constraints of the Company's contract with Monsanto. I
first reviewed the Company's annual results of operations reports since 20054 to
reveal the number of times in a year Monsanto load was actually curled at the
time of the system peak. The table below shows that from April 2004 though
December 2009 Monsanto curlment events occured at the time of the monthly
system peak at most five times durng a given year.
4 The ¡PUC apoved the Revise Protocol Stipulation on Febrar 28, 2005.
McDougal, Di-Reb '" 45
Rocky Mountan Power
Curtilment Events at Hour of Monthly System Pea
FY2005 FY2006 CY200 CY2007 CY200 CY209
Januar
Februar
March
April
May
June x x
July x x x
August x x x x
September x x
October x
November x x x x
December x x x
Count 3 3 5 5 1 2
1 All of the events in the table above are the result of economic curailment;
2 no operating reserve events occured at the time of the system peale Based on
3 that historical record I removed Monsanto load from 6 of the 12 monthly
4 coincident peaks, conservatively representing curailment events durng a given
5 year. I removed 70.3 MW (67 MW adjusted for line losses) from Idao
6 jursdictional peak, representing the economic curailment porton of the contract
7 adjusted for line losses. In additiòn, I removed 850 hour of curailed energy
8 from the Idaho jursdictional energy, and I removed retail revenue for reduced
9 sales priced at the non-fir energy rate. This scenaro reduces the overall price
10 change to Idaho in this case from $24.9 miion (the Company's rebutta position)
11 to $18.7 millon, a reduction of $6.2 mion.
12 To get a better idea of the net impact on customers, this reduce revenue
13 requirment must be allowed to flow though a simiarly impacted cost of service
14 study. The tables below compare Monsanto's allocated cost of service under the
15 Company's rebuttl fiing and a corrected non-fi alocation scnaro.
McDougal, Di-Reb - 46
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Company Rebuttal
Description Annual
Rewnue
Total
Cost of
Servce
Increae
(Decreae)
to = ROR
13,996,524
Percentage
Change frm
Currnt RelÆnues
9.82%142,524,117 156,520,641
59.544,497 7'0,397,959
202,04,614 226,918,594
All Others
Non-Firm Scenario
Description Annual
Revenue
Total
Cost of
Servce
Increase Percentage
Chage frm
Currnt Revenues
9.89%142,524,117 156,622,051
ss.1$a,s1a6?,73?,~é
200,692,635 219,354,077
Under the non-fir allocation scenaro, Monsanto's allocated cost of service is
$7.7 millon less than under the Company's rebuttal results. However,
Monsanto's allocated cost of service in the Company's rebutta filng would be
offset by the separate payment from the Company related to the value of the
curment products. There would be no separte payment under the non-firm
scenaro. Under the non-fir scenaro, if the Company were to pay a curlment
payment or credit (as we have done in the past several contracts) it would results
in a double counting of curaient benefits. The ultiate net impact on
Monsanto relative to the allocation methodology wil be determed by the value
ascribed to the curent products, an issue that wil be determed in a separate
phase of this case.
Do you agree with Ms. Iverson's asserton that the Revised Protocol
treatment of Monsanto is a fiction that ha resulted in increases to Monsanto
year after year?
No. The Revised Protocol was an agreement between paries in Idao as well as
staeholders across four states that underwent significant scrutiy and analysis.
McDougal, Di-Reb - 47
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The primary purpose of the Revised Protocol was to achieve a consistent method
for allocating costs and benefits of providing service across the Company's multi-
state service terrtory. The cost of providing service to all of our customers in
Idaho has certinly risen since the Revised Protocol was adopted, but the
allocation methodology itself is not the man drver of rate increases to Monsanto.
Was Monsanto a party to the Stipulation supporting the Revised Protocol
approved in Case No. PAC-E-02-3?
Yes. Monsanto was a pary to the stipulation reached in that case supporting the
use of the Revised Protocol, and the signing paries to the Stipulation believed the
terms of the Stipulation were fai, just, and reasonable.
Is the allocation of costs and benefits related to special contracts with
industrial customers a signifcant issue addresse in the Revised Protocol?
Yes. The issue of allocating costs and benefits related to special contracts is
repeated several times as an importt issue addressed with the Revised Protocol
agreement. PacifiCorp's comments supportg the Stipulation state, "The
Revise Protocol, if ratified by all of PacifiCorp' s state commssions, wil
establish uniorm policies in respect to a number of critical issues. These
include.. .how the costs and benefits of special contracts with industral customers
wil be allocated among states."s In addition, the joint motion for approval of the
settlement signed by PacifCorp and the Idao Commssion staff identifies that
the Revised Protocol addresses the alocation of special contracts.
5 Page 4, PacCorp Comments in Support of Joint Motion for Acceptance of Settlement, Case No. PAC-E-
02-3.
McDougal, Di-Reb - 48
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Please provide the language from the Revised Protocol that specifically deals
with the treatment of Monsnto's special contract.
Appendix D of the Revised Protocol describes the treatment of special contracts,
including those with ancilar service contract attbutes such as the Company's
contract with Monsanto. Specifically, the Revised Protocol states:
"For allocation puroses Special Contracts with Ancilar Service
Contract attrbutes are viewed as two transactions. PacifiCorp sells the
customer electrcity at the retail service rate and then buys the electrcity
back durg the interrption period at the Ancilar Service Contract rate.
Loads of Special Contract customers wil be included in all Load-Based
Dynamic Allocation Factors. When interrptions of a Special Contract
customer's service occur, the host jursdiction's Load-Based Dynamc
Allocation Factors and the retail service revenue are calculated as though
the interrption did not occur. Revenues received from Special Contract
customer, before any discounts for Customer Ancilar Service attrbutes
of the Special Contract, wil be assigned to the State where the Special
Contract customer is located. Discounts from taff prices provided for in
Special Contracts that recognize the Customer Ancilar Service Contract
attrbutes of the Contract, and payments to retail customers for Customer
Ancilar Services wil be allocated among States on the same basis as
System Resources."
Have you treated the Company's agreement with Monsanto as a specia
contract with ancilary service contract attributes, as described in Appendi
D of the Revised Protool?
Yes. In the Company's original filg, Monsanto's load is included in the load-
based dynamic alocation factors, and the retal revenue is calculated as if there is
no interrption and is dict assigned to Idao. In addition, the cost of the
ancilar services is allocated among all states on the same basis as other system
resources. The Company's rebuttal filing continues to treat the Monsanto special
contract in this maner.
McDougal, Di-Reb - 49
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What is the appropriate forum for Monsanto to address the allocation of the
costs and benefits related to its special contract?
The MSP Standing Commttee was established as par of the Revised Protocol to
"oversee continuing analytical efforts associated with inter-jurisdictional
issues.. .and serve as a forum for the paries to discuss and hopefully resolve
emerging inter-jurisdictional issues. Meetigs of the MSP Standing Commtte
are to be open to all interested paries. Those meetings are expected to assist in
maitaining an ongoing consensus among PacifiCorp's states regardig inter-
jurisdictional issues, thereby preserving the accomplishments of the MSp"6
(emphasis added). It is of utmost importance to the Company that issues affecting
multiple states be brought to the MSP Stading Commttee in an effort to preserve
consistent allocations across paricipating states. Altering treatment of one
special contrct in this case simply because another method produces a smaler
rate increase for one customer is inconsistent with the signed stipulation.
Ms. Iverson compares her proposed alloction treatment of Monsanto
curtent to the Idaho irrigation load control program and another special
contract with a Rocky Mountain Power customer in Utah. Do you agree that
her proposl is comparable to these other examples?
No. Ms. Iverson's proposal is much more aggressive than the treatment of either
of these programs. As mentioned previously, Ms. Iverson removed 170.1 MW of
Monsanto demand in all twelve months of the year. Whe jursdctional load is
reduced for curlment from Idao irgators and the Utah special contract, it is
6 Page 6, Orer No. 29708, Cas No. PAC-E-Q2-3.
McDougal, Di-Reb - 50
Rocky Mountai Power
1 limited to curtailment achieved pursuant to the terms of the respective agreements
2 and is limited to a specific number of months.
3 Q.Do you have additional concerns with the comparison to the Idaho irrgation
4 load control program?
5 A.Yes. In this case the Idao Commssion staff, ICL and Idao Irgation Pumpers
6 Association each proposed that the costs and benefits of the Idao irgation load
7 control program be allocated system-wide, rather than the current treatment. But
8 Monsanto points to the irgation load control program as an example of proper
9 situs treatment. This varation of proposals highlights the Company's concern
10 that circumventing the agreed-upon process of addressing multi-state issues
11 though the MSP Standig Commttee results in short sighted decisions and
12 continued inconsistent treatment.
13 I(Wo Irrigation Load Control Program
14 Q.Pleas describe the positions taken by parties with respect to the Idaho
15 Irrgation Load Control Program.
16 A.The Idao Irgation Load Control Program is addressed by multiple paries in the
17 case. I wil briefly describe some of the positions in the case.
18 Mr. Don C. Reading proposes that "the Commssion, Company, and other
19 paries should purue allocating the irgation load control program, Schedules 72
20 and 72A, as a system wide resource. Whe ths proposal liely requires a change
21 to the Revised Protocol for inteijursdictional cost allocations, we believe it is a
22 reasonable and prudent proposal.,,7
7 Diect testiny of Don Reaing, page 2, lies 9 - 12.
McDougal, Di-Reb - 51
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Mr. Yanel proposes that "in the long term (by the next rate case), that this
program be treated more as a system benefit where the curments are 'sold' to
the system at their tre value." He also proposes that the Company increase the
curlment used in this case to the amount that was available.
Mr. Lobb and Ms. Terr Carlock for the Commssion staff both fied
testimony on the irgation program. Mr. Lobb claims that the costs of the
Irgation Load Control program assigned to Idaho customers is inequitable when
compared to the program benefits received. Ms. Carlock supports assigning the
costs of the irgation program as a power supply cost.
Do you agree with Mr. Lobb and Ms. Carlock that the program contracts are
more like purchas power agreements or ancilary service contracts and
should be similarly system allocted?
The Company agrees that there are characteristics that make the irgation
program more like an interrptible progra. However, the Company believes
that this decision needs to be made by the MSP Standing Commttee, and needs to
be consistently applied to all Class 1 DSM progrms.
Do you agree with Mr. Reading's proposal that the Commision, Company,
an other paries should purue allocating the irrgation load control
progra as a system resource?
Although the Company does not believe ths should be done in this case, the
Company is not oppose to Mr. Reading's proposal as long as it is done in the
correct foru and is applicable to clearly defied resources. As mentioned
previously, the Company believes that ths decision needs to be made by the MSP
McDougal, Di-Reb - 52
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Standig Commttee, and needs to be consistently applied to all Class 1 DSM
programs.
Did the Company incorrctly include only 229 MW of progrm participation
in the jurisdictional load decrement as alleged by Mr. Yankel?
No. As described in the Company's responses to IIPA data requests 64 and 90
sponsored by Dr. Eelkema, as well as in Dr. Eelkema's diect testimony, the
229MW included in the fiing is the correct amount as it represent the level of
potential interrptibilty of paricipating loads durng a given dispatch event.
Do you agree with Ms. Carlock's conclusion that a classification change for
thi program would allow it to be system allocated under the Revised
Protocol?
No. As stated in my diect testiony, this program as a Class 1 DSM progrm.
According to Section iv, Subpar C of the Revised Protocol, demand-side
management programs are assigned to the State Resources category. According to
the Revised Protocol:
"Costs associated with Demand-Side Management Program wil be
assigned on a situs basis to the State in which the investment is made.
Benefits from these programs, in the form of reduce consumption, wil be
reflected though tie in the Load-Base Dynamc Allocation Factors."
The Company believes that there is sufficient justication to bring ths
issue before the MSP stadig Commttee for resolution.
Do you agre with Mr. Yanel's propos revision to the curent
adjustment?
No. Mr. Yankel proposes to revise the curent values for June, July and
McDougal, Di-Reb - 53
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August to 234 MW, 260 MW and 246 MW respectively.8 However, as shown on
Tab 5, page 6 of Exhibit 49, the contribution to the coincident peak for the entire
irtation class during those thee months is only 277 MW, 180 MW and 178MW.
Mr. Yankel's proposal would remove 260 MW in July, even though the entire
irgation class, including those not on the interrptible schedule, is only 180
MW. This same result occurs durng the month of August when Mr. Yanel
would remove 246 MW and the irgation class contrbution to the coincident
peak is only 178 MW.
Do any other jurisdictions served by PacifiCorp have simiar programs, and
are those programs treated in a similar manner in this cae?
Yes. The Company operates programs to control irgation and central ai
conditioning load in its Uta service terrtory. Both of these program are trated
in a similar manner as the Idao irgation program, i.e. the Uta load used to
compute inter-jursdictional allocation factors is reduced to reflect program
paricipation and the program costs are diect assigned to Utah.
Did any party propose adjusting this ca for the Utah progrms?
No. All adjustments made in this case were to the Idao irgation only. None of
the pares attempted to adjust ths case for Uta Class 1 DSM programs. If a
change is made, it should be a universal change with specifc rules about which
programs qualiy for system treatment.
What changes does the Company propoe to its filig in ths cae?
None. As noted above, the Company believes the irgation program is treated
corrtly in this rate case. The Company proposes that the paries brig ths issue
8 Yanel di testimony, page 31, lie 12.
McDougal, Di-Reb - 54
Rocky Mounta Power
1 before the MSP Standing Commttee to make a recommendation on how to trat
2 all Class 1 DSM programs.
3 Other Issues
4 Q.
5
6 A.
7
8
9
10
11
12
13
14 Q. ~
15
16 A.
17
18
19
20
21
22
Did any party file testimony in opposition to the Company's proposed
treatment of revenue from the sale of renewable energy credits ("RECs")?
No. The Company's original filng proposed that RECs wil be included as a
revenue credit in the Company's energy cost adjustment mechansm ("ECAM")
fiings. Accordingly, the Company plans on incorporating RECs into the ECAM
mechanism staring Januar 1,2011. The base level ofREC revenue wil be
$91,779,696 on a total Company level, and $7,031,166 on an Idaho alocated
basis as shown on pages 3.6.1 though 3.6.3 of my Exhbit No.2, with varations
deferred and recovered or refunded on a dollar for dollar basis in subsequent
ECAM proceedings.
Did any party file testimony regarding the Load Growth Adjustment Rate
("LGAR")?
Yes. Mr. Yanel addressed the LGAR in his filed testimony. He presents
arguments related to the application of the WAR in the Company's ECAM
filngs, specifcally arguing that the LGAR should only be utilized in situations
where load is increasing and not when load decreases. Mr. Yankel states that he
is not addressing the level or dollar amount of the WAR, but he recommends that
the LGAR is only to be applied in ECAM cases where there has been growth on
the Company's system.
McDougal, Di-Reb - 55
Rocky Mounta Power
1 Q.
2 A.
3
4
5
6
7
8
9
10
11 Q.
12
13 A.
14
15
16
17
18
19
20
Is Mr. Yankel's discussion relevant to this genera rate case?
No. The WAR is only utilzed in the Company's ECAMfilings, and is not
relevant to the outcome of this general rate case. As par of the settlement
reached to establish the ECAM mechanism, the Company agreed to update the
calculation of the LGAR each time base net power costs are updated in general
rate cases. The Company provided that calculation in Exhibit NO.4. The
application of the LGAR, however, has no relevance to ths case and should be
addressed in the context of the ECAM. The Commssion Staf has aleady held
technical workshops outside the scope of this case and work on this issue should
continue in a separate venue.
Did the Company update the calculation of the LGAR along with its rebuttal
filing?
Yes. I have included an updated LGAR calculation as Exhbit No. 80. When
preparg the updated LGAR calculation, the Company discovered an error in
Exhibit NO.4. In the Company's original calculation of the LGAR, wheeling
expenses is removed from total production expenses to arve at the unbundled
production revenue requirement excludig net power costs. However, the total
production expenses did not include wheeling expense to begin with. The
unbundled production revenue requirement excluding net power costs is correctly
calculated in Exhibit No. 80.
McDougal, Di-Reb - 56
Rocky Mounta Power
1 Summary
2 Q.
3
4 A.
5
6
7
8
9 Q.
10 A.
Please summarize your position on the rebuttal revenue requirement
proposed by the Company?
The modified revenue requirement of $24.9 millon is the appropriate revenue
requirement based on the test period used in this case. The Company has carefully
reviewed the adjustments proposed by the parties and either made adjustments
that it believes are appropriate in this case or defended the proposals put forth by
the Company in its original filing.
Doe this conclude your rebuttl testimony?
Yes.
McDougal, Di-Reb - 57
Rocky Mountan Power
Case No. PAC-E-10-07
Exhibit No. 78
Witness: Steven R. McDougal
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Rebuttal Testimony of Steven R. McDougal
Revenue Requirement Summ
November 2010
Rocky Mountain Power
IDAHO
Results of Operations. REVISED PROTOCOL
12 Months Ended DECEMBER 2009
1 Operating Revenues:
2 Geerl Business Revenues
3 Interdepartental
4 Special Sales
5 Other Operang Revenues
6 Total Operating Revenues
78 Openg Expenes:
9 Steam Prouction
10 Nuclear Production
11 Hydro Production
12 Oter Power Supply
13 Transmission
14 Distnbution
15 Customer Accounting
16 Customer Serice & Info
17 Sales
18 Administrtive & General
19
20 Total O&M Expenses
21
22 Depreiation
23 Amization
24 Taxes Other Than Income
25 Income Taxes. Federal
26 Income Taxes. State
27 Income Taxes. De Net
28 Investment Tax Cre" Adj.
29 Misc Revenue & Expense
30
31 Totl Opertig Expenses:
32
33 Operating Rev For Retum:
34
35 Rate Base:
36 Elect Plant In Serice
37 Plant Held for Future Use
38 Misc Defer Debits
39 Bee Plant Acq Adj
40 Nucr Fuel
41 Prepayments
42 Fuel Stock
43 Matenal & Supplies
44 Workng Capit
45 Weaenza Loans
46 Misc Rate Base
47
48 Totl Elecc Plant:
49
50 Rate Base Deons:
51 Acc Pro For Dere
52 Acc Prov For Amo
53 Accum Def Income Tax
54 Unamoid ITC
55 Custome Adv For Cost
56 Cusomer Seice Depits
57 Mise Rate Base Des
58
59 Tota Rate Bae Deductons
60
61 Tot Rat Bas:
62
63 Retur on Rate Base
64
65 Retrn on i;qui
66
67 TAX CALCULATION:
68 Op Revene69 Ot Deucons
70 Inert (AFUDC)
71 Intert72 Sd "M" Addit73 Scule "M" Deuc
74 In Be Tax
75
76 Slae In Taxesn Tax In
78
79 Fed Ine Taxes + Oter
(1)Tot
Results
202,733,162
47,181.395
13,773,496
263.68,052
60,435,375
2,133,930
81.047,814
10,746,876
11,434,56
4,643,836
1,847,458
11,489,496
183,779,349
27,431,473
2,100,494
5,735,434
(30,337,63)
(3,698,423)
40,613,922
(201,494)
(58,936)
224,842.185
38,845867
1,166,794,057
(0)
4,174,122
3,352.852
2,570,384
12,146,067
9,955,856
2,927.613
3,503,640
123,279
1,205,547,851
(371,626,719)
(21,60,207)
(155,69,797)
(226,270)
(947,697)
(4,891,303)
(55,992.992)
6555 85
5.971%
6.058%
45.222.238
(3,235,728)
18,208,250
43,182.28
152,89,957
(79.458.95)
(3,69,423)
(7578533,
(39 33763'
(2)
Pnce Change
24.669,96
57,60
8,289,995
1,126,473
9,474,274
15395 705
24,812,173
24,812,173
1,126,473
2368701
828999
Rocky Mountain Power
Exhibit No. 78 Page 1 of 1
Case No. PAC-E-10-07
Witness: Steven R. McDougal
(3)
Resultsw"h
Pri Change
227,603,142
4,701,642
5,735,434
(22,047,638)
(2,571,951 )
234,316,459
54 24157
1.205,547.851
(554,992.992)
6555 859
8.338%
10.60
70,034,411
(3.235,728)
18.208.250
43,182,285
152,890,957
(54,646,783)
(2,571,951 )(52 07483'
'2204763'
Case No. PAC-E-10-07
Exhibit No. 79
Witness: Steven R. McDougal
BEFORE THE IDAHO PUBLIC UTLITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Rebuttal Testimony of Steven R. McDougal
Results of Operations Sumar
November 2010
Rocky Mountain Power Page 1.0
IDAHO
Results of Operations. REVISED PROTOCOL
12 Months Ended DECEMBER 2009
(1)(2)(3)
Total ResuRswRh
Results Price Change Pri Change
1 Operating Revenues:
2 General Busins Revenues 202,733,162 24,869,980 227,603,142
3 Interdepartntal
4 Special Sales 47,181,395
5 Othr Operating Revenues 13,773,496
6 Total Oprating Revenues 263,688,052
7
8 Operating Expenses:
9 Steam Production 60,435,375
10 Nuclar Prouction
11 Hydro Prouction 2,133.930
12 Other Power Suppiy 81,047,814
13 Transmission 10,746,876
14 Distributon 11.434.56
15 Customer Accounting 4,643,836 57,80 4,701,642
16 Cuomer Service & Info 1,647,458
17 Sales
18 Administrative & Geerl 11.489,496
19
20 Total O&M Expenses 183,779.349
21
22 Deprecation 27,431,473
23 Amortization 2.100,494
24 Taxes Ot Thanlncome 5,735,434 5.735,434
25 Income Taxes. Federal (30,337,634)8,289.995 (22,047,638)
26 Incoe Taxes. State (3,698,423)1,126.73 (2.571,951 )
27 Incoe Taxes. De Net 40,613,922
28 Investment Tax Credit Adj.(201,494)
29 Misc Revenue & Expense (58,936)
30
31 Total Operating Expenses:224,842,185 9,474,274 234,316,459
32
33 Operng Rev For Retum:38,845867 15395705 54 241 573
34
35 Rate Base:
36 Elecric Plant In Service 1,166,79,057
37 Plant Hetd for Future Use (0)
38 Misc Deered Deits 4,174,122
39 Elee Plant Acq Adj 3.352,852
40 Nuclear Fuel
41 Prepayments 2,570.364
42 Fuel Stock 12,146,067
43 Materal & Supplies 9.955.85
44 Worng Capital 2.927,613
45 Weathzation Lons 3,503,640
46 Mise Rate Bae 123,279
47
48 Totl Elec Plant:1.20,547.851 1,205,547,851
49
50 Rate Bae Deucts:
51 Accum Proy For Deree (371,626.719)
52 Accum Prov For Amo (21,60.207)
53 Accum De Income Tax (155,694.797)54 Unamo ITC (226,270)
55 Custoer Adv For Cont (947,697)
58 Customr Servic Deposits
57 Misc Rat Ba Deucons (4,891,303)
58
59 Totl Rate Base Deuctions (56,992,992)(56.99.992)
60
61 Totl Rae Base:65'55 85 65 56 859
62
63 Retur on Rate Bae 5,971%8.336%
64
65 Re on Equit 6.05%10.60%
66
67 TAX CALCULATION:68 Op Reven 45,22.238 24,812,173 70,034,41169 Ot De
70 in (AFUDC)(3.235,728)(3.235.728)
71 Irer 18.20,250 18,208,2572 Sc oM" Addl 43.182,285 43.182,28573 Sc OM" Deon 152,890,957 152,890,957
74 In Beor Tax (79,458,95)24.812.173 (54,646.783)
75
76 Sla In Taxes (3,69,423)1,126,473 (2.571.951)77 Tax Inom as1653)?3§85701 (52074 832)
78
79 Fedln Taxes + Oter (3033763)8289:95 (22 047 63)
Rocky Mountain Power
RESULTS OF OPERATIONS
Page 2.1
USER SPECIFIC INFORMATION
STATE:
PERIOD:
IDAHO
DECEMBER 2009
FILE:
PREPARED BY:
DATE:
TIME:
JAM Dec 2009 ID GRC_Rebuttal
Revenue Requirement Department
11/10/2010
10:20:51 AM
TYPE OF RATE BASE:
ALLOCATION METHOD:
Year-End
REVISED PROTOCOL
FERC JURISDICTION:Separate Jurisdiction
8 OR 12 CP:12 Coincidental Peaks
DEMAND %
ENERGY %
75% Demand
25% Energy
TAX INFORMATION
TAX RATE ASSUMPTIONS:
FEDERAL RATE
STATE EFFECTIVE RATE
TAX GROSS UP FACTOR
FEDERAUSTATE COMBINED RATE
TAX RATE
35.00%
4.54%
1.615
37.951%
CAPITAL STRUCTURE INFORMATION
CAPITAL
STRUCTURE
EMBEDDED
COST
WEIGHTED
COST
DEBT
PREFERRED
COMMON
47.60%
0.30%
52.10%
100.00%
5.88%
5.42%
10.60%
2.799%
0.016%
5.523%
8.338%
OTHER INFORMATION
The Company's current estimated cost of equity is 10.6%. The capital structure is calculated using the five quarter average from
12/3112009 to 1213112010.
REVISED PROTOCOL Page 2.2
Year.End
RESULTS OF OPERATIONS SUMMARY
UNADJUSTED RESULTS IDAHO
Description of Account Summary:Ref TOTAL OTHER IDAHO ADJUSTMENTS ADJ TOTAL
1 Operating Revenues
2 General Business Revenues 2.3 3,484,413,565 3,297,654,176 186,759,389 15,973.773 202,733,162
3 Interdepartental 2.3 0 0 0 0 0
4 Special Sales 2.3 643,321,157 608,334,858 34,986.299 12,195,096 47,181,395
5 Other Operating Revenues 2.4 226,031,658 211,768,618 14.263,041 (489,545)13,773,96
6 Total Operating Revenues 2.4 4,353,766,380 4,117,757,652 236,008,729 27,679,324 263,688,052
7
8 Operating Expenses:
9 Steam Producton 2.5 898,300,862 843,721,653 54,579,209 5.856,165 60,435,375
10 Nuclear Production 2.6 0 0 0 0 0
11 Hydro Production 2.7 37,924,259 35,835,202 2,089,057 44.873 2,133,930
12 Other Power Supply 2.9 1,023,694,683 957,342,697 66,351,986 14,695,828 81,047.814
13 Transmission 2.10 172,874,522 163.342,030 9,532,492 1.214,384 10,746,876
14 Distribution 2.12 215,468,741 204,320,401 11,148,340 286.225 11,434.564
15 Customer Accounting 2.12 93,785,007 89,279,506 4,505.501 138.335 4,643,836
16 Customer Service & Infor 2.13 71,462.744 64,626,109 6.836,635 (4,989,177)1.847,458
17 Sales 2.13 0 0 0 0 0
18 Administrative & General 2.14 162,619,511 153,146,104 9,473,407 2.016,089 11,489,496
19
20 Total 0 & M Expenses 2.14 2,676,130,329 2,511,613.702 164,516,627 19,262,722 183,779.349
21
22 Depreciation 2.16 464,027,603 439,654,747 24,372,857 3,058,616 27,431,473
23 Amortization 2.17 43,698,570 41.447,110 2.251,459 (150,965)2,100,494
24 Taxes Other Than Income 2.17 123,877,487 118,556,052 5,321,434 414,000 5,735,434
25 Income Taxes - Federal 2.20 (169,095,879)(155,246,71 )(13,849,408)(16.488,225)(30,337,634)
26 Income Taxes - State 2.20 (22,619,435)(20,716,041)(1,903,395)(1.795,029)(3,698,23)
27 Income Taxes - Def Net 2.19 482,616,183 458,788.432 23,827,751 16,786,171 40,613.922
28 Investment Tax Credit Adj.2.17 (1.874,204)(1,672,710)(201,494)0 (201,494)
29 Mise Revenue & Expense 2.4 (5,975,707)(5,678.965)(296,743)(284,193)(580,936)
30
31 Total Operating Expenses 2.20 3,590,784,945 3,386,745,857 204,039,088 20,803,097 224,842,185
32
33 Operating Revenue for Retum 762,981,435 731,011.794 31.969,641 6,876,226 38,845,867
34
35 Rate Base:
36 Eiectiic Plant in Service 2.30 19,556,037,605 18,501,513,991 1,054,523,614 112.270,443 1,166,794.057
37 Plant Held for Future Use 2.31 13,674,549 13,104,516 570,032 (570,032)(0)
38 Mise Deferr Debit 2.33 140,117,584 136,496,764 3,620.820 553,302 4.174,122
39 Elec Plant Acq Adj 2.31 60,866,907 57.514,055 3.352,852 0 3,352,852
40 Nuclear Fuel 2.31 0 0 0 0 0
41 Prepayments 2.32 46,150,453 43,580,089 2,570,364 0 2.570,364
42 Fuel Stock 2.32 167,792,599 157,165,766 10,626,832 1,519,234 12.146,067
43 Mateiial & Supplies 2.32 177,874.022 167,918,166 9,955,856 0 9,955.856
44 Working Capitl 2.33 55,801,121 52,891,524 2,909,597 18.016 2,927,613
45 Weatherition Loans 2.31 37,358,188 33,854,547 3,503,640 0 3.503.64
46 Miscellaneous Rate Base 2.34 1,809,172 1,685,894 123.279 0 123.279
47
48 Total Electic Plant 20.257,482,199 19,165,725,311 1,091,756,888 113,790,963 1,205.547,851
49
50 Rate Base Deductns:
51 Accum Prov For Depr 2.38 (6.626,518.392)(6,257,435,755)(369,082,637)(2,544,082)(371,626.719)
52 Accum Prov For Amort 2.39 (427.140,689)(405,559,885)(21,580,804)(25,402)(21,606,207)
53 Accum Def Income Taxes 2.35 (2,332,318,663)(2,191,771,766)(140,546,897)(15,147,900)(155.694,797)
54 Unamorted ITC 2.35 (7.294,222)(7,250,054)(44,168)(182,102)(226.270)
55 Customer Adv for Const 2.34 (20,944,658)(20,258,001 )(686,658)(261,039)(947,697)
56 Customer Service Deposits 2.34 0 0 0 0 0
57 Misc. Rate Base Deductions 2.34 (57.36,419)(54,678,805)(2,686,614)(2,204.689)(4,891,303)
58
59 Total Rate Base Deducions (9,471,582,03)(8,936,954,265)(534,627.778)(20,365,213)(554,992,992)
60
61 Total Rate Base 10,785,900,156 10,228,771.046 557,129,110 93,425,749 650.554.859
62
63 Retum on Rate Base 7.074%5.738%5.971%
64
65 Return on Equit 8.174%5.611%6.058%
66 Net Powr Costs 1,042,847,444 67,040,143 69,008,495
67 100 Basis Points in Equity
68 Revenue Requirement Impact 90.56.779 4,677,985 5,462,442
69 Rate Base Decrase (739,90,478)(46.373,11 )(52,207,202)
REVISED PROTOCOL Page 2.3
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
70 Sales to Ultimate Customers
71 440 Residential Sales
72 0 S 1,346,519,773 1,287,272,744 59,247,029 386,357 59,633,386
73
74 61 1,346,519,773 1.287,272,744.59,247,029 386,357 59,633.386
75
76 442 Commercial & Industrial Sales
77 0 S 2,097,948,247 1.970,908,587 127.039,660 15,459,595 142,499.255
78 P SE
79 PT SG
80
81
82 81 2.097,948,247 1,970.908,587 127,039,660 15,59,595 . 142,499,255
83
84 44 Public Street & Highway Lighting
85 0 S 20.913,398 20,440,698 472.700 127.821 600.521
86 0 SO
87 81 20,913,398 20,40.698 472.700 127.821 600,521
88
89 445 Oter Sales to Public Authority
90 0 S 19.032,148 19,032,148
91
92 61 19,032,148 19.032,148
93
94 448 Interde partmental
95 DPW S
96 GP SO
97 81
98
99 Total Sales to Ultimate Customers B1 3,48.413.565 3.297,654.176 186,759,389 15,973,773 202,733,162
100
101
102
103 447 Sales for Resale-Non NPG
104 WSF S 8.352.641 8,352.641
105 8.352,641 8.352.641
106
107 447NPG Sales for Resale-NPC
108 WSF SG 633,900,033 598.981,663 34.918,370 12,263,025 47.181.395
109 WSF SE 1,068,483 1.000,554 67,929 (67,929)
110 WSF SG
111 634.96.516 599,982,217 34,986.29 12.195.096 47,181,395
112
113 Total Sales for Resale 81 643.321,157 608,334.858 34,986,299 12,195.096 47,181,395
114
115 449 Provision for Rate Refund
116 WSF S
117 WSF SG
118
119
120 81
121
122 Total Sales from Eleccit B1 4,127,734,722 3,905,989,034 221,745,688 28,168,869 249,914,557
123 45 Foneited Discounts & Interest
124 GUST S 7,318.368 6.907.026 411.342 411.342
125 GUST SO
126 81 7,318,368 6.907.026 411,342 411,342
127
128 451 Mise Electrc Revenue
129 CUST S 6,902.761 6.732,681 170,080 170.080
130 GP SG
131 GP SO 6.131 5.801 331 331
132 81 6.908,893 6,738,82 170,411 170,411
133
134 453 Water Sales
135 P SG 12,155 11,485 670 670
136 81 12,155 11,485 670 670
137
138 45 Rent of Elect Propert
139 DPW S 10,421,181 10,119.677 301.504 301,504
140 T SG 5.304.571 5.012.36 292.202 292,202
141 T SG 4.88 4,617 269 269
142 GP SO 3.428.294 3.243,429 184.864 184,864
143 81 19,158.931 18.380,092 778.840 778,840
144
145
REVISED PROTOCOL Page 2.4
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
146
147 456 Other Electric Revenue
148 OMSC S 50,609.068 45,598,459 5.010,609 (5,010.486)123
149 CU5T CN
150 OTHSE SE 8,005,386 7,496,442 508.944 508,944
151 OTHSO SO 173,123 163,788 9,335 9,335
152 OTHSGR SG 133,845,735 126,472,845 7,372,890 4,520,941 11.893,830
153
154
155 81 192,633.312 179.731,534 12,901,778 (489,545)12,412.233
156
157 Total Other Electric Revenues B1 226,031,658 211,768,618 14,263,041 (489,545)13,773,496
158
159 Total Electnc Operating Revenues B1 4,353,766,380 4,117,757,652 236,008,729 27,679,324 263,688,052
160.
161 Summary of Revenues by Factor
162 S 3,568,017,584 3,375,364,659 192,652.925 10,963,287 203,616,212
163 CN
164 SE 9.073,869 8,496,996 576,873 (67,929)508.944
165 SO 3,607,548 3,413.018 194,530 194,530
166 SG 773.067.379 730,482,978 42,58,400 16,783,96 59,368,366
167 OGP
168
169 Total Electric Operating Revenues 4,353,766,380 4,117,757,652 236,008,729 27,679,324 263.88,052
170 Miscellaneous Revenues
171 41160 Gain on Sale of Utilty Plant - CR
172 OPW 5
173 T SG
174 G 50
175 T SG
176 P SG
177 81
178
179 41170 Loss on Sale of Utilty Plant
180 DPW 5
181 T SG
182 81
183
184 4118 Gain from Emission Allowances
181 P S
1(16 P SE (3.790,891 )(3.549.88)(241,007)(284,193)(525,200)
187 B1 (3,790.891 )(3,549,884)(241,007)(284,193)(525,200)
188
189 41181 Gain from Disposition of NOX Credits
190 P SE
191 81
192
193 4194 Impact Housing Interest Income
194 P SG
195 B1
196
197 421 (Gain) I Loss on Sale of Utilty Plant
198 OPW 5 (1.173,272)(1.173,272)
199 i SG (145.556)(137,538)(8.018)(8,018)
200 T SG (68.192)(64,436)(3,756)(3,756)
201 PTO CN
202 PTO 50 12,862 12,169 694 694
203 P SG (810.657)(766,002)(44,655)(44.655)
204 81 (2,184,816)(2.129,080)(55,736)(55,736)
205
206 Total Miscellaneous Revenues (5,975,707)(5,678,965)(296,743)(284,193)(580,936)
207 Miscllaneous Expenses
208 4311 Interest on Customer Deposits
209 CUST S
210 81
211 Totl Miscellaneous Expeses
212
213 Net Mlsç Revenue and Expense B1 (5,975,707)(5,678,965)(296,743)(284,193)(580,936)
214
REVISED PROTOCOL Page 2.5
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
215 500 Operation Supervision & Engineering
216 P SG 20,160.039 19.049.523 1,110,515 37.227 1.147,743
217 P SSGCH 1,216,352 1,150,085 66,267 66,267
218 82 21,376,391 20,199,608 1,176,783 37,227 1,214.010
219
220 501 Fuel Related-Non NPC
221 P SE 11,157,930 10,448,562 709,368 1,067 710,434
222 P SE
223 P SE
224 P SSECT
225 P SSECH 3,213.384 3,019,906 193,478 193,478
226 82 14,371,314 13,468,468 902,846 1,067 903,912
227
228 501NPC Fuel Related-NPC
229 p SE 552,903,370 517,752,418 35,150,952 5,399,987 40,550.938
230 P SE
231 P SE
232 P SSECT
233 P SSECH 52.991,371 49,800,763 3,190.608 73,828 3.264,437
234 82 605,894,741 567,553.181 38,341,560 5,473,815 43,815,375
235
236 Total Fuel Related 620,266,055 581,021,649 39,244,405 5,474,882 44,719.287
237
238 502 Steam Expenses
239 P SG 30,407,397 28,732,406 1,674,991 41,453 1,716,444
240 P SSGCH 5,101,692 4,823.751 277,942 277,942
241 82 35,509,090 33,556.157 1,952.933 41,453 1,994,385
242
243 503 Steam From Other Sources-Non-NPC
244 P SE 147 147
245 B2 147 147
246
247 503NPC Steam From Other Sources-NPC
248 P SE 3,597,576 3,368,859 228,717 (14,218)214,498
249 82 3,597.576 3,368.859 228,717 (14,218)214,498
250
251 505 Electc Expenses
252 p SG 2,754,507 2,602,775 151,732 3,675 155,407
253 P SSGCH 1,150,021 1,087.367 62,654 62,654
254 B2 3,904,528 3,690.143 214,385 3.675 218,060
255
256 506 Misc. Steam Expense
257 P SG 42,056,734 39,740,040 2.316,694 91,485 2,408.180
258 P SE
259 P SSGCH 1,502,518 1,420,661 81.858 (1)81,857
260 B2 43,559,253 41,160,701 2,398.552 91,485 2,490,037
261
262 507 Rents
263 p SG 44,653 423,939 24,714 24,714
264 P SSGCH 1,762 1.666 96 96
265 B2 450,415 425.605 24,810 24,810
266
267 510 Maint Supervision & Engineering
268 P SG 4,057,736 3,834,216 223,520 33,811 257,331
269 P SSGCH 1,912,378 1.808,191 104,187 104,187
270 B2 5,970,114 5,642,407 327,707 33,811 361,518
271
272
273
274 511 Maintenance of Strctures
275 P SG 21,88,763 20.681,131 1.205,632 14,388 1.220,020
276 P SSGCH 938.302 887,183 51,119 (2)51.117
277 B2 22,825.065 21,568,314 1,256,751 14,386 1,271,137
278
279 512 Maintenanc of Boiler Plant
280 P SG 91,029,755 86,015,382 5,014,372 141.730 5,156,102
281 P SSGCH 3.403,827 3,218,385 185,442 (298)185,144
282 82 94,433.581 89,233,767 5.199,814 141.432 5.341,246
283
284 513 Maintenanc of Eleic Plant
285 P SG 33,316,896 31,481,635 1,835,260 25,634 1,860,894
286 P SSGCH 410,626 388,255 22,371 22,371
287 82 33,727,522 31,869,890 1,857,632 25,634 1,883,266
288
289 514 Maintenanc of Mi. Steam Plant
29 p SG 9,86.457 9,128,311 532.146 6.265 538,411
291 P SSGCH 3,20.817 2,856.242 164,575 (11)164,564
292 82 12,681,274 11,984,553 696,721 6,254 702,975
293
294 Totl Steam Power Gelon B2 898,300,862 84,721,653 54,579,209 5,856,165 60,435,375
REVISED PROTOCOL Page 2.6
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
295 517 Operation Super & Engineering
296 P SG
297 62
298
299 518 Nuclear Fuel Expense
300 P SE
301
302 62
303
304 519 Coolants and Water
305 P SG
306 62
307
308 520 Steam Expenses
309 P SG
310 62
311
312
313
314 523 Electric Expenses
315 P SG
316 62
317
318 524 Misc. Nuclear Expenses
319 P SG
320 82
321
322 528 Maintenance Super & Engineering
323 P SG
324 62
325
326 529 Maintenance of Structures
327 P SG
328 82
329
330 530 Maintenance of Reactor Plant
331 P SG
332 82
333
334 531 Maintenance of Electric Plant
335 P SG
336 82
337
338 532 Maintenance of Mise Nuclear
339 P SG
340 62
341
342 Total Nuclear Power Generation B2
343
344 535 Operation Super & Engineering
345 P DGP
346 P SG 8.095,683 7,649.732 44.951 9,813 455.763
347 P SG 1,289,537 1,218,502 71.034 10,929 81.963
348
349 62 9,385,219 8,868.235 516.985 20.742 537.726
350
351 536 Water For Power
352 P DGP
353 P SG 285.794 270,051 15,743 193 15.936
354 P SG 4,415 4.172 243 (5)238
355
356 62 290,209 274.223 15.986 188 16,174
357
REVISED PROTOCOL Page 2.7
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
358 537 Hydraulic Expenses
359 P DGP
360 P SG 3,168,766 2,994,214 174,551 1,298 175,850
361 P SG 349,844 330,573 19,271 146 19,417
362
363 82 3,518,610 3,324,787 193.823 1.44 195,267
364
365 538 Electric Expenses
366 P DGP
367 P SG
368 P SG
369
370 82
371
372 539 Misc. Hydro Expenses
373 P DGP
374 P SG 11,894,606 11,239,392 655.214 10,025 665,239
375 P SG 5,705,129 5.390,862 314,267 7,665 321,932
376
377
378 82 17,599,735 16,630,254 969,481 17,690 987,171
379
380 540 Rents (Hydro Generation)
381 P DGP
382 P SG 180,404 170,466 9.938 (31)9.907
383 P SG 3,040 2,873 167 (3)165
384
385 82 183,444 173,339 10,105 (33)10,072
386
387 541 Maint Supervision & Engineenng
388 P DGP
389 P SG 84,358 79,711 4,647 2 4,649
390 P SG
391
392 82 84,358 79,711 4.647 2 4,649
393
394 542 Maintenance of Structures
395 P DGP
396 P SG 1,092,399 1,032,224 60.175 606 60,781
397 P SG 114,713 108.394 6,319 196 6,515
398
399 82 1.207,112 1,140,619 66,494 .802 67,296
400
401
402
403
404 543 Maintenance of Dams & Waterways
405 P DGP
406 P SG 1.189.774 1,124.235 65,539 632 66,170
407 P SG 410,765 388,138 22,627 280 22,907
408
409 82 1,600,539 1,512.374 88,166 912 89.077
410
411 544 Maintenance of Electnc Plant
412 P DGP
413 P SG 1.188,647 1.123,171 65,477 1,140 66,617
414 P SG 327,068 309,052 18,017 531 18,54
415
416 82 1.515,716 1,432.223 83,493 1,671 85,164
417
418 545 Maintenance of Misc. Hyro Plant
419 P DGP
420 P SG 1,925.303 1,819,248 106.055 1,076 107.132
421 P SG 614.013 580,190 33.823 379 34.202
422
423 82 2,539,316 2,399,438 139.878 1,455 141,333
424
425 Total Hydraulic Power Geeration B2 37,924,259 35,835,202 2,089,057 44,873 2,133,930
REVISED PROTOCOL Page 2.8
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
426
427 546 Operation Super & Engineenng
428 P SG 316,964 299,504 17,460 63 17,523
429 P SSGCT
430 B2 316,964 299,504 17,460 63 17,523
431
432 547 Fuel-Non-NPC
433 P SE
434 P SSECT
435 B2
436
437 547NPC Fuel-NPC
438 P SE 426,253,895 399,154,711 27,099,184 2,694,748 29,793,932
439 P SSECT 35,489,120 33,231.922 2,257,199 (1.369,207)887,991
440 B2 461,743,015 432,386.633 29,356.382 1,325,541 30,681,924
441
442 548 Generation Expense
443 P SG 14,113.019 13,335,604 777,415 10,615 788,031
444 P SSGCT 1,626,465 1,537.686 88,779 1,884 90,663
445 B2 15.739,485 14,873,290 866,194 12,499 878,693
446
447 549 Miscellaneous Other44P SG 18,635,853 17,609,298 1,026,556 330,179 1,356;734
449 P SSGCT
450 B2 18,635.853 17,609,298 1,026,556 330,179 1,356,734
451
452
453
454
455 550 Rents
456 P SG 1.861.263 1,758.736 102,528 102,528
457 P SSGCT
458 B2 1.861,263 1,758,736 102,528 102,528
459
460 551 Maint Supervision & Engineenn9
461 P SG
462 B2
463
464 552 Maintenance of Structures
465 P SG 1.350,705 1,276,301 74,404 455 74,859
466 P SSGCT 193,326 182,774 10,553 156 10.709
467 82 1,544,031 1,459,075 84,956 611 85,567
468
469 553 Maint of Generation & Electn Plant
470 P SG 12,141,793 11,472,963 668,830 (218,736)450,094
471 P SSGCT 2,845,046 2,689.752 155,294 450 155,744
472 B2 14,986.840 14,162.715 824,124 (218,287)605,838
473
474 554 Maintenance of Misc. Other
475 P SG 1,200,375 1,134,253 66,123 97 66,220
476 P SSGCT 121,530 114,897 6,634 184 6,817
477 B2 1,321,906 1,249,150 72,756 281 73.037
478
479 Total Other Power Generation 82 516,149,358 483,798,401 32,350,957 1,450,887 33,801,844
480
481
482 555 Purcased Power-Non NPC
483 DMSC S (33,207,768)(33,362,478)154,710 (154,710)
484 (33,207,768)(33,362,478)154,710 (154,710)485
486 555NPC Purchase Power-NPC
487 P SG 409,727,945 387,158,090 22,569,855 6,802.349 29,372,204
488 P SE 79,691,472 74,625,070 5,066,403 (584.201)4,482,201
489 Seasonal Co P SSGC
490 DGP
491 489,419,417 481,783,159 27,636,258 6,218,147 33,854,405
492
493 Total Purcsed Powr B2 456,211,649 428,20.681 27,790.968 6,063,437 33,854,405
494
495 556 System Control & Load Dispatch
496 p SG 1,514,461 1.431,037 83,424 1,524 84,948
497
498 82 1,514,461 1,431,037 83,24 1,524 84,948
499
500
REVISED PROTOCOL Page 2.9
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
501
502 557 Other Expenses
503 P S (183,792)(150,819)(32,973)7,585,721 7.552,748
504 P SG 48,880,583 46,187,997 2,692,586 (405,742)2,286,844
505 P SGCT 1,122,425 1,060,360 62,065 62,065
506 P SE
507 P SSGCT
508 P TROJP
509
510 B2 49.819.215 47,097.537 2,721,678 7.179,979 9.901,657
511
512 Embedded Cost Differentials
513 Company Owned Hyd P DGP (65,082,413)(65,082,413)
514 Company Owned Hyd P SG 65,082,413 61,497,350 3,585,063 3,585,063
515 Mid-C Contract P MC (39,855,992)(38,798,578)(1,057,414)(1,057,414)
516 Mid-C Contract P SG 39,855,992 37,660,526 2,195,466 2,195,466
517 Existing QF Contracts P S 42,959,299 41,911,043 1.046,256 1,048.256
518 Existing QF Contracts P SG (42,959,299)(40,592,887)(2,366,412)(2.366,412)
519
520 (3,404,959)3,404,959 3.404.959
521
522 Total Other Power Supply B2 507,545,325 473.54,296 34,001,030 13,244,941 47,245,970
523
524 Total Production Expense B2 1.959,919,804 1,836,899,552 123,020,252 20,596,867 143,617,119
525
526
527 Summary of Production Expense by Factor
528 S 9,567,738 8,397,746 1,169.992 7,431.011 8,601,003
529 SG 865,425,265 817,753,332 47,671.933 6,961.345 54,633.277
530 SE 1.073,604,242 1,005.349,620 68,254.622 7,497.528 75.752.151
531 SNPPH
532 TROJP
533 SGCT 1.122,425 1.060,360 62,065 62,065
534 DGP (65.082,413)(65,082,413)535 DEU
536 DEP
537 SNPPS
538 SNPPO
539 DGU
540 MC (39.855.992)(38,798,578)(1,057,414)(1.057,414)
541 SSGCT 4,786,369 4,525,109 261.259 2,673 263,932
542 SSECT 35,489,120 33.231.922 2.257.199 (1.369,207)887,991
543 SSGC
544 SSGCH 18,658.295 17,641.785 1.016,510 (312)1,016.198
545 SSECH 56.204.755 52.820.669 3.384.086 7~,828 3,457,914
546 Total Production Expense by Factor B2 1,959.919.804 1.836.899,552 123,020,252 20.59 ,867 143,617,119
547 560 Operation Supervision & Engineering
548 T SG 6,088.583 5,753,193 335.389 10.916 346,305
549
550 B2 6,088,583 5.753,193 335.389 10.916 346,305
551
552 561 Load Dispatching
553 T SG 9.323.709 8,810.112 513,596 18.577 532,174
554
555 B2 9.323.709 8,810.112 513,596 18,577 532,174
556 562 Station Expense
557 T SG 1.506,478 1,423,494 82.984 2.259 85,243
558
559 B2 1.506.478 1,423,494 82,984 2.259 85.243
560
561 563 Overhead Line Expense
562 T SG 245.152 231.64 13.504 206 13.710
563
584 B2 245.152 231.64 13.504 206 13.710
565
566 564 Underground Line Exense
567 T SG
568
569 B2
570
REVISED PROTOCOL Page 2.10
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
571 565 Transmission of Electricity by Others
572 T SG
573 T SE
574
575
576 565NPC Transmission of Electricity by Others-NPC
577 T SG 116,018,414 109,627,542 6,390,872 1,066,721 7,457,592
578 T SE 1,142,797 1,070,143 72,654 93,442 166,095
579 117,161,210 110,697.685 6,463.525 1,160,162 7,623.688
580
581 Total Transmission of Electricity by Others 82 117,161.210 110.697,685 6,63.525 1,160.162 7,623,688
582
583 566 Misc. Transmission Expense
584 T SG 2,393,112 2.261,287 131,825 (4,285)127,540
585
586 B2 2,393.112 2.261.287 131,825 (4,285)127,540
587
588 567 Rents - Transmission
589 T SG 1,656.975 1,565,700 91,274 509 91,784
590
591 82 1,656,975 1,565,700 91,274 509 91,784
592
593 568 Maint Supervision & Engineering
594 . T SG 35,453 33,500 1,953 39 1,992
595
596 82 35,453 33.500 1,953 39 1,992
597
598 569 Maintenance of Strctures
599 T SG 4,060,560 3.836,884 223,676 5,435 229.110
600
601 B2 4,060,560 3,836,884 223,676 5,35 229.110
602
603 570 Maintenance of Station Equipment
604 T SG 10,549,624 9,968,98 581,126 16.773 597,899
605
606 82 10.549,624 9,968,98 581.126 16,773 597,899
607
608 571 Maintenance of Overhead Lines
609 T SG 19,620,066 18,539,295 1.080,771 3.679 1,084,449
610
61~62 19,620,066 18,539.295 1.080.771 3,679 1,084,449
612
613 572 Maintenance of Underground Lines
614 T SG 51.599 48,757 2,82 84 2,926
615
616 B2 51,599 48,757 2.842 84 2,926
617
618 573 Maint of Misc. Transmission Plant
619 T SG 182,001 171.976 10,026 30 10,056
620
621 62 182,001 171,976 10,026 30 10.056
622
623 Total Transmission Expese B2 172,874,522 163,342,030 9,532,492 1,214,384 10,746,876
624
625 Summary of Transmission Exnse by Factor
626 SE 1,142,797 1,070,143 72,654 93,442 166,095
627 SG 171,731,725 162,271,887 9,459.839 1,120,942 10.580,781
628 SNPT
629 Total Transmission Expense by Factor 172,874,522 163,342,030 9,532,492 1,214,38 10,746,876
630 - 580 Operation Supervision & Engineering
631 DPW S 1.012,443 930,166 82.277 82,277
632 DPW SNPD 18,641,946 17,781,836 860.111 34,479 894,590
633 82 19.654.389 18,712.001 942.388 34,479 976,867
63463 581 Load Dispatcing63DPW S
637 DPW SNPD 13.439,746 12.819,657 620.089 25,714 645.803
63 62 13,439.746 12,819.657 620.089 25.714 645,803
63964 582 Statin Expe
641 DPW S 3,849,839 3,641,292 208,547 4,008 212,555
642 DPW SNPD 29,848 28,471 1.377 46 1,42364B23,879.687 3,669,763 209,924 4,053 213,977
644
REVISED PROTOCOL Page 2.11
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
645 583 Overhead Line Expenses
646 DPW S 5,777,056 5,475,120 301,936 11,118 313,054
647 DPW SNPD 17,767 16,948 820 29 849
648 62 5,794.824 5,492,068 302,756 11,147 313,903
649
650 584 Underground Line Expense
651 DPW S 305 305
652 DPW SNPD
653 62 305 305
654
655 585 Street Lighting & Signal Systems
656 DPW S
657 DPW SNPD 207,152 197,594 9,558 402 9,960
658 62 207,152 197.594 9.558 402 9,960
659
660 586 Meter Expenses
661 DPW S 5,630,733 5,374,972 255,761 9,193 264,954
662 DPW SNPD 1,082,827 1.032,867 49,960 1,765 51,725
663 62 6,713,56 6,407,839 305,721 10,958 316.679
664
665 587 Customer Instllation Expenses
666 DPW S 12,458,762 12,009,848 448,917 16,305 465,222
667 DPW SNPD 496 473 23 1 24
668 62 12,459,259 12.010,319 44,940 16.306 465,248
669
670 588 Misc. Distribution Expenses
671 DPW S 1,903,892 1,827,783 76.109 (2,139)73,970
672 DPW SNPD 5.537,508 5,282,016 255,492 (46)255,44
673 62 7,441,400 7,109,799 331,601 (2,186).329,416
674
675 589 Rents
676 DPW S 3,082,013 3,056,279 25,733 33 25,767
677 DPW SNPD 1.14,242 108,971 5,271 0 5,271
678 62 3,196,255 3,165,250 31,004 33 31,038
679
680 590 Maint Supervision & Engineering
681 DPW S 1,168,290 1,079,917 88,373 3,126 91,498
682 DPW SNPD 6,367,680 6,073,885 293,795 10,425 304,219
683 62 7,535,970 7,153,82 382,168 13,550 395,718
684
685 591 Maintenance of Strutures
686 DPW S 1,855,991 1,709,849 146,142 146,142
687 DPW SNPD 159,999 152,617 7.382 7,382
688 62 2.015,990 1,862,466 153.524 153,524
689
690 592 Maintenance of Station Equipment
691 DPW S 10,926.178 10,135,064 791.114 25.517 816,631
692 DPW SNPD 1,874,179 1,787,708 86,472 3,387 89,858
693 62 12.800,357 11.922,771 877.586 28.904 906,490
694 593 Maintenance of Overhead Lines
695 DPW S 82,112.317 77,011,054 5,101,264 100,942 5.202,206
696 DPW SNPD 1.224,337 1,167,84 56,489 951 57,440
697 62 83.336,655 78,178,902 5,157,753 101.893 5,259,646
698
699 594 Maintenance of Underground Lines
700 DPW S 22,479,205 21,746,414 732.791 18.984 751,774
701 DPW SNPD 7,391 7,050 341 11 352
702 82 22,486,595 21.753,464 733,132 18.995 752,126
703
704 595 Maintenance of Line Transformers
705 DPW S 24,717 24,717
706 DPW SNPD 1.081,164 1.031,280 49,883 1.698 51,581
707 82 1.105.880 1.055,997 49.883 1.698 51.581
708
709 596 Maint of Strt Lighting & Signal Sys.
710 DPW S 4.217,687 4,084,975 132,712 4.670 137,382
711 DPW SNPD
712 82 4,217.687 4,084,975 132,712 4,670 137.382
713
REVISED PROTOCOL Page 2.12
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAl
714 597 Maintenance of Meters
715 DPW S 4.536.131 4,239.464 296,667 10.873 307.541
716 DPW SNPD 1.100.892 1.050.098 50.793 1,662 52,455
717 82 5.637.023 5.289.562 347,461 12.535 359.996
718
719 598 Maint of Misc. Distribution Plant
720 DPW S 2.967.838 2.882.374 85,465 128 85.592
721 DPW SNPD 578.169 551.493 26.676 2.944 29.620
722 82 3.546.007 3,433.867 112.141 3.072 115.212
723
724 Total Distribution Expense 62 215,468,741 204,320,401 11,148,340 286,225 11,434,56
725
726
727 Summary of Distribution Expense by Factor
728 S 164.003.397 155.229.589 8.773.808 202.757 8.976,565
729 SNPD 51,465.344 49,090.812 2.374.532 83,467 2,457.999
730
731 Total Distribution Expense by Factor 215,468,741 204,320,401 11.148.340 286,225 11,434.564
732
733 901 Supervision
734 CUST S 102.805 87.017 15,788 56 15,84
735 CUST CN 2.451.290 2.356.068 95.222 4.004 99.226
736 82 2.554.096 2,443.085 111.010 4.060 115.070
737
738 902 Meter Reading Expense
739 CUST S 20,750.177 19.136.393 1.613,784 62.513 1.676.297
740 CUST CN 1,770.041 1.701,283 68.758 2.274 71.033
741 82 22,520.219 20.837.676 1.682.543 64.787 1.747.330
742
743 903 Customer Receipts & Collections
744 CUST S.7,352.864 7.023.206 329.657 10.345 340.002
745 CUST CN 48.927.462 47.026.843 1.900.620 58.841 1.959,461
746 82 56.280.326 54.050.049 2.230.277 69.186 2.299.463
747
748 904 Uncollectible Accounts
749 CUST S 12.149.005 11.677.783 471,222 471.222
750 P SG
751 CUST CN 26.790 25.749 1.041 1.041
752 82 12.175.795 11.703.532 472.263 472.263
753
754 905 Misc. Customer Accounts Expense
755 CUST S 12.390 12.390
756 CUST CN 242.182 232.774 9,408 302 9.710
757 82 254.572 245.164 9,408 302 9.710
758
759 Total Customer Accounts Expense B2 93,785,007 89,279,506 4,505,501 138,335 4,643,836
760
761 Summary of Customer Acct Exp by Factor
762 S 40.367,241 37.936.789 2,430,452 72.914 2,503.366
763 eN 53.417.766 51,342.717 2.075,049 65,421 2.140,470
764 SG
765 Total Customer Accounts Expense by Factor 93.785.007 89.279.506 4,505,501 138.335 4.643.836
766
767 907 Supervision
768 CUST S
769 CUST CN 286.417 275.290 11.126 396 11.523
770 82 286,417 275.290 11.126 396 11.523
771
772 908 Customer Assistance
773 CUST S 63,240,907 56.710.070 6.530,837 (4.992.585)1.538,252
774 CUST CN 2.861,099 2.749,957 111,141 4.430 115,571
775
776
777 82 66,102.006 59,460.027 6,641,979 (4.988,155)1.653.823
778
REVISED PROTOCOL Page 2.13
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
779 909 Informational & Instrctional Adv
780 CUST S 349.724 349,724
781 CUST CN 4.574.542 4.396,841 177.701 (1,426)176.275
782 B2 4.924,267 4.746.566 177.701 (1,426)176,275
783
784 910 Misc. Customer Service
785 CUST S
786 CUST CN 150.055 144,226 5,829 8 5.837
787
788 82 150.055 144.226 5.829 8 5.837
789
790 Total Customer Service Expense B2 71.462.744 64,626,109 6.836.635 (4.989,177 1,847,458
791
792
793 Summary of Customer Service Exp by Factor
794 S 63.590.631 57.059.794 6.530,837 (4.992.585)1,538.252
795 CN 7.872.112 7.566.315 305.797 3,408 309.206
796
797 Total Customer Service Expense by Factor B2 71,462.744 64.626,109 6,836.635 (4.989.177)1.847,458
798
799
800 911 Supervision
801 CUST S
802 CUST CN
803 82
804
805 912 Demonstration & Sellng Expense
806 CUST S
807 CUST CN
808 B2
809
810 913 Advertising Expnse
811 CUST S
812 CUST CN
813 B2
814
815 916 Misc. Sales Expense
816 CUST S
817 CUST CN
818 82
819
820 Total Sales Expense 82
821
822
823 Total Sales Expense by Factor
824 S
825 CN
826 Total Sales Expense by Factor
827
828 Total Customer Service Exp Including Sales B2 71,462,744 64.626,109 6,836,635 (4,989,177)1,847,458
829 920 Administrtive & General Salaries
830 PTO S (4.135.538)(5.140.020)1.004,482 (1.004.482)
831 CUST CN
832 PTD SO 77,010,359 72.857.716 4.152.643 180.816 4.333,459
833 B2 72,874,820 67.717.696 5,157.125 (823.665)4.333,459
834
835 921 Ofce Supplies & expenses
836 PTD S (568.262)(568.412)150 150
837 CUST CN
838 PTO SO 11,599.34 10.973.875 625,474 (31.319)594.155
839 82 11.031.87 10.405,463 625.624 (31,319)594.305
840
841 922 A&G Expenses Transferrd
842 PTO S
843 CUST CN
844 PTD SO (25.866,776)(24,471,957)(1.394.819)69,015 (1.325.804)
845 82 (25.866,776)(24,471.957)(1.394,819)69,015 (1,325.804)
846
REVISED PROTOCOL Page 2.14
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
847 923 Outside ServiceS
848 PTD S 630 630
849 CUST CN
850 PTD SO 11,038,720 10,443,477 595.243 (25,987)569,256
851 B2 11,039,350 10,444,107 595,243 (25,987)569,256
852
853 924 Propérl Insurance
854 PTD 50 23,970,318 22.677,762 1.292,556 1,292,556
855 B2 23.970.318 22,677.762 1,292.556 1.292,556
856
857 925 Injuries & Damages
858 PTD 50 7,434,336 7.033,453 400,883 113,443 514,326
859 B2 7,434,336 7,033.453 400,883 113,443 514.326
860
861 926 Employee Pensions & Benefits
862 LABOR 5
863 CU5T CN
864 LABOR 50
865 B2
866
867 927 Franchise Requirements
868 DM5C 5
869 DM5C 50
870 B2
871
872 928 Regulatory Commission Expense
873 DM5C 5 11,943.931 11,526.839 417,092 4.691 421,783
874 CU5T CN
875 DM5C 50 2,197,338 2,078,850 118.487 78 118,565
876 FERC 5G 2,323,478 2.195.489 127.989 127,989
877 B2 16,464.747 15,801.178 663,568 4,769 668,337
878
879 929 Duplicate Charges
880 LABOR 5
881 LABOR 50 (3,20.843)(3,236,380)(184,463)(246)(184.709)
882 82 (3,420,843)(3,236,380)(184.483)(246)(184.709)
883
884 930 Misc General Expenses
885 PTD S 5,290,870 5.282.370 8,500 196,497 204,997
886 CUST CN 4.500 4.325 175 (44)131
887 LABOR SO 14.400.017 13.623,522 776,495 2,503.688 3.280,183
888 B2 19.695,387 18,910.217 785,169 2,700.141 3,485.311
889
890 931 Rents
891 PTD 5 961.066 961.086
892 PTD 50 5,238.518 4,956,040 282,478 282,478
893 B2 6,199,584 5,917,107 282,478 282,478
894
895 935 Maintenance of General Plant
896 G 5 15,577 15,577
897 CUST CN
898 G SO 23,181.924 21,931.881 1.250,043 9.939 1,259.982
899 B2 23,197,501 21,947,458 1,250,043 9,939 1,259,982
900
901 Total Administrative & General Expense 82 162,619,511 153,146,104 9,473,407 2,016,089 11,489,496
902
903 5ummary of A&G Exnse by Factor
904 5 13,508,275 12,078,050 1,430,224 (803,294)626.930
905 50 146.783,259 138.868,240 7,915,019 2,819,427 10,734,446
906 5G 2,323,478 2,195.489 127,989 127,989
907 CN 4,500 4,325 175
Ó44)
131
908 Total A&G Expense by Factor 162,619,511 153,146,104 9,473,407 2,016, 89 11,489,496
909
910 Totl O&M Expese 82 2,676,130,329 2,511,613,702 164,516,627 19,262.722 183,779,349
REVISED PROTOCOL Page 2.15
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
911 403SP Steam Depreciation
912 P SG 23,110,000 21,836,987 1.273,014 1,273,014
913 P SG 25,963,107 24.532,930 1,430,177 1,430,177
914 P SG 52,664,788 49,763,750 2,901.039 806.887 3.707.926
915 P SSGCH 7,785,936 7.361.756 424.180 424.180
916 B3 109.523,832 103,495,421 6.028,410 806,887 6,835.297
917
918 403NP Nuclear Depreciation
919 p SG
920 B3
921
922 403HP Hydro Depreciation
923 P SG 3,645,429 3,444.621 200.808 200.808
924 P SG 1,016,491 960,498 55,993 55.993
925 P SG 7.347,198 6,942,478 404,720 24,768 429,488
926 P 5G 3,441,241 3,251,681 189,561 189,561
927 B3 15,450,360 14.599,277 851.083 24,768 875.850
928
929 4030P Other Producton Depreciation
930 P 5G 124.817 117.942 6,876 6.876
931 P SG 94,515,821 89,309,419 5.206.402 1,032,439 6,238,841
932 P SSGCT 2,54,778 2,405,874 138,904 138.904
933 P 5SGCH
934 B3 97,185,416 91,833,234 5.352,182 1.032,439 6,384,620
935
936 403TP Transmission Depreciation
937 T SG 11,260,768 10,640,469 620.299 620,299
938 T SG 12,574,497 11,881,831 692,666 692.666
939 T SG 39.057,941 36,906,435 2.151,506 1,182,236 3,333,741
940 B3 62,893,206 59,428,735 3,464,471 1,182,236 4.646,706
941
942
943
944 403 Distribution Depreciation
945 360 Lim & Land Righi. DPW S 292,392 274,904 17,488 17,488
946 361 Strures DPW S 1,016,944 993,937 23,007 23,007
947 362 Sloìon Equipmt DPW 5 17,275,368 16,659,953 615,415 615,415
948 363 $t'llO aolter Eqi DPW 5 91.113 91,113
949 364 Pole & Tower DPW S 33,365,759 31,345,364 2,020.396 1.199 2.021,595
950 365 OH Cors DPW S 18.807.119 17.850,287 956,832 956,832
951 366 UG Conduit DPW 5 7,529,925 7.372,273 157.652 157,652
952 367 UG Conducr DPW S 17,412,373 16.938,733 473.640 473,640
953 368 UneTra DPW S 26,759.726 25,342,167 1,417.559 1,417,559
954 369 Service DPW S 11.531,258 11.013,789 517,468 517,468
955 370 Meie DPW S 6,509,338 6,062.663 44,676 446,676
956 371 Inst Co Pr DPW 5 496,358 488,788 7,570 7.570
957 372 lea Propey DPW S
958 373 St_ Lighl DPW 5 2,255,605 2,226.651 28.954 28,954
959 B3 143,343.279 136,660.621 6,682.658 1.199 6,683,857
960
961 403GP General Depreciation
962 G-8ITU5 S 12,310.835 11,555,600 755,235 (173)755,062
963 PT 5G 502.163 474.501 27.662 27,662
964 PT SG 706,142 667,244 38.898 38,898
965 P SE 26.236 24.568 1,668 1,668
966 CUST CN 1.759.170 1.690,834 68.33 68,336
967 G-SG 5G 5,229,908 4.941.819 288,089 2,848 290,938
968 PTD 50 14,946,453 14,140,493 805,960 8,413 814,373
969 G-8G 5SGCT 6,010 5.682 328 328
970 G-SG SSGCH 144.595 136.718 7,878 7.878
971 B3 35,631.512 33.637,458 1.994,053 11,088 2.005,141
972
973 403GVO General Vehicles
974 G-G SG
975 B3
976
977 403MP Mining Deprian
978 P SE
979 B3
980
REVISED PROTOCOL Page 2.16
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
981 403EP Expenmental Plant Depreiation
982 P SG
983 P SG
984 B3
985 4031 ARO Depreciation
986 P S
987 B3
988
989
990 Total Depreciation Expense 83 464,027,603 439,654,747 24,372,857 3,058,616 27,431,473
991
992 Summary S 155,654,113 148,216,221 7,437,892 1,026 7,438,918
993 DGP
994 DGU
995 SG 281,160,312 265,672,602 15,87,710 3,049,177 18,536,887
996 SO 14,946,453 14,140,493 805.960 8,413 814,373
997 CN 1,759,170 1,690,834 68,336 68,336
998 SE 26,236 24.568 1,668 1,668
999 SSGCH 7,930,531 7,498,473 432,08 432,058
1000 SSGCT 2,550,788 2,411.556 139.232 139,232
1001 Total Depreciation Expense By Factor 464,027,603 439,654,747 24,372.857 3,058,616 27,431,473
1002
1003 404GP Amort of L T Plant. Capital Lease Gen
1004 I-SITUS S 1,345,062 1,345,062
1005 I-SG SG
1006 PTD SO 929,374 879,259 50,115 50,115
1007 P SG
1008 CUST CN 249,571 239,876 9.695 9.695
1009 P SG
1010 B4 2,524,007 2,464,198 59,810 59.810
1011
1012 404SP Amort of L T Plant. Cap Lease Steam
1013 P SG
1014 P SG
1015 64
1016
1017 4041P Amort of L T Plant - Intangible Plant
1018 I-SITUS S 94,304 73,772 20,532 20,532
1019 P SE 14,498 13,577 922 922
1020 I-SG SG 8,952,161 8,459.032 493,130 25,402 518,532
1021 . PTD SO 13,131,339 12,423,255 708.083 9,540 717,624
1022 CUST CN 5,000,879 4.806,617 194,262 194.262
1023 I-SG SG 2,615,413 2,471,343 144,070 5,786 149,856
1024 I-SG SG 310,432 293,332 17,100 17,100
1025 P SG
1026 I-SG SSGCT
1027 I-SG SSGCH 54,934 51,941 2,993 2,993
1028 P SG 16,758 15,835 923 923
1029 64 30,190,717 28,608,702 1,582,015 40,728 1,622,743
1030
1031 404MP Amort of L T Plant. Mining Plant
1032 P SE
1033 64
1034
1035 4040P Amort of L T Plant - Other Plant
1036 P SG
1037 84
1038
1039
1040 404HP Amortization of Other Elecmc Plant
1041 P SG 6.589 6,226 363 363
1042 P SG 40,392 38,167 2,225 2,225
1043 P SG
1044 B4 46,981 44,393 .2,588 2,588
1045
1046 Totl Amrtiztion of Limied Term Plant B4 32,761,706 31,117,293 1,64,413 40,728 1,685,141
1047
1048
1049 405 Amorttin of Other Elect Plant
1050 GP S
1051
1052 B4
1053
REVISED PROTOCOL Page 2.17
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1054 406 Amortization of Plant Acquisition Adj
1055 P S
1056 P SG
1057 P SG
1058 P SG 5,479,353 5,177,523 301,830 301,830
1059 P SO
1060 B4 5,479,353 5,177,523 301,830 301,830
1061 407 Amort of Prop Losses, Unrec Plant, etc
1062 DPW S (36,176)(36,176)
1063 GP SO
1064 P SG-P 3,479,961 3,288.268 191,694 (191,694)0
1065 P SE
1066 P SG
1067 P TROJP 2.013,725 1,900,202 113,523 113.523
1068 B4 5,457,511 5,152,294 305,217 (191,694)113,523
1069
1070 Total Amortization Expense B4 43,698,570 41,447,110 2,251,459 (150,965)2,100,494
1071
1072
1073
1074 Summary of Amortization Expense by Factor
1075 S 1,403,190 1,382,658 20.532 20,532
1076 SE 14,498 13,577 922 922
1077 TROJP 2,013,725 1.900.202 113,523 113,523
1078 DGP
1079 DGU
1080 SO 14.060,713 13.302,514 758,198 9,540 767,739
1081 SSGCT
1082 SSGCH 54.934 51,941 2,993 2.993
1083 SG-P 3,479,961 3,288,268 191,694 (191.694)0
1084 CN 5,250,450 5,046,493 203,957 203,957
1085 SG 17,421,098 16,461,458 959,641 31,188 99.829
1086 Total Amortzation Expense by Factor 43,69.570 41,447.110 2,251,459 (150,965)2,100,494
1087 408 Taxes Other Than Income
1088 DMSC S 25,320,436 25,320,436
1089 GP GPS 87,317,409 82.608,977 4.708.432 414.000 5,122,432
1090 GP SO 10,522,150 9,954,763 567,388 567,388
1091 P SE 717,492 671,877 45,615 45.615
1092 P SG
1093 DMSC OPRV-ID
1094 GP EXCTAX
1095 GP SG
1096
1097
1098
1099 Totl Taxes Other Than Income B5 123,87,487 118,556,052 5,321,434 414,000 5,735,434
1100
1101
1102 41140 Deferred Investment Tax Credit - Fed
1103 PTD DGU (1.874.204)(1,672,710)(201,494)(201,494)
1104
1105 B7 (1,874.204)(1,672,710)(201,494)(201,494)
1106
1107 41141 Deferred Investment Tax Creit-Idaho
1108 PTD DGU
1109
1110 B7
1111
1112 Totl Deferred ITe B7 (1,874,204)(1,672,710)(201,494)(201,494)
1113
REVISED PROTOCOL Page 2.18
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1114
1115 427 Interest on Long.Term Debt
1116 GP S (423,149)(423,149)
1117 GP SNP 369.236.117 349.630.156 19.605,962 19.605.962
1118 B6 369.236.117 349.630,156 19.605,962 (423.149)19.182.812
1119
1120 428 Amortization of Debt Disc & Exp
1121 GP SNP 6.571.354 6.222,423 348,930 348.930
1122 B6 6,571.354 6,222,423 348,930 348,930
1123
1124 429 Amortization of Premium on Debt
1125 GP SNP (2,718)(2,574)(144)(144)
1126 B6 (2,718)(2.574)(144)(144)
1127
1128 431 Other Interest Expense
1129 NUTIL OTH
1130 GP SO
1131 GP SNP 10.264.106 9.719.095 545.011 545.011
1132 B6 10.264,106 9.719,095 545.011 545.011
1133
1134 432 AFUDC . Borrowed
1135 GP SNP (35.186.532)(33.318.172)(1.868.359)(1.868.359)
1136 (35.186.532)(33.318.172)(1,868.359)(1.868.359)
1137
1138 Total Elec. Interest Deductions for Tax B6 350.882.327 332.250.928 18.631.399 (423.149)18.208.250
1139
1140 Non-Utilty Portion of Interest
1141 427 NUTIL NUTIL
1142 428 NUTIL NUTIL
1143 429 NUTIL NUTIL
1144 431 NUTIL NUTIL
1145
1146 Total Non-utilit Interest
1147
1148 Total Interest Deductions for Tax B6 350.882.327 332.250.928 18.631.399 (423.149)18.208.250
1149
1150
1151 419 Interest & Dividends
1152 GP S
1153 GP SNP (60.559.377 160,217
1154 Total Operating Deductions for Tax B6 7
1155
1156
1157 41010 Deferrd Income Tax. Federal.DR
1158 GP S 26.529,700 26.102.344 427.356 (347.371)79.985
1159 P TROJD 735.881 694.228 41.653 41,653
1160 P SSGCH 26.126 24,703 1,423 1,423
1161 LABOR SO 37.814.180 35.775.119 2.039,061 (275.931)1,763.129
1162 GP SNP 35.849.593 33.946.026 1.903.567 1,903.567
1163 P SE 23.499.301 22.005.328 1.493.973 206,34 1.700.807
1164 PT SG 51.291.699 48,466.297 2.825,402 17.727.662 20.553.064
1165 GP GPS 31.266.44 29.580.45 1.685.986 1.685.986
1166 TAXDEPR TAXEPR 615.608.170 584.405.196 31.202.974 31.202.974
1167 eUST BADDEBT 443.332 426.136 17.196 17.196
1168 eUST eN 22,893 22.004 889 889
1169 P IBT 348.313 319.003 29.310 (29.310)
1170 DPW SNPD 67.978 64,82 3.136 3.136
1171 B7 823,503,606 781,831.680 41.671.926 17.281.885 58.953.811
1172
REVISED PROTOCOL Page 2.19
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DE SCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1173
1174
1175 41110 Deferred Income Tax - Federal-eR
1176 GP S (26,854,405)(25,660,209)(1,194,196)322.685 (871.511 )
1177 P SE (17.999.483)(16,855,162)(1,144,321)233.209 (911,112)
1178 P SSGCH (538.368)(509.038)(29,330)(29,330)
1179 GP SNP (31,616,890)(29,938,074)(1,678,816)(1,678.816)
1180 PT SG (7,932,473)(7,495.513)(436,960)(1,082,112)(1.519.072)
1181 DPW crAC (20.332,44)(19.394,336)(938,108)(938,108)
1182 LABOR SO (28,202,710)(26,681,930)(1,520,780)(5.505)(1,526,285)
1183 PT SNPD (1,949,167)(1,859,235)(89,932)(89,932)
1184 CUST BADDEBT
1185 P SGCT (356.221)(336.523)(19,698)(19,698)
1186 BOOKDEPR SCHMDEXP (203,344.850)(192,664,248)(10,680,604)(10.680,604)
1187 P TROJD (1,332,481 )(1,257,059)(75,22)(75,422)
1188 P IBT (427,931)(391,921)(36.010)36.010
1189
1190
1191 B7 (340,887,423)(323,043,248)(17,844,175)(495,713)(18,339,889)
1192
1193 Total Deferred Income Taxes B7 482,616,183 458,788,432 23,827,751 16,786,171 40,613,922
1194 SCHMAF Additions - Flow Through
1195 SCHMAF S
1196 SCHMAF SNP
1197 SCHMAF SO
1198 SCHMAF SE
1199 SCHMAF TROJP
1200 SCHMAF SG
1201 B6
1202
1203 SCHMAP Additions - Permanent
1204 P S 20,000 20,000
1205 P SE 90.872 85,095 5,777 5,777
1206 LABOR SNP
1207 SCHMAP-SO SO 12,568,198 11,890,481 677,717 677,717
1208 SCHMAP SG
1209 DPW BADDEBT
1210 B6 12.679,071 11,995,576 683,494 683,494
1211
1212 SCHMAT Additions - Temporary
1213 SCHMA T -51T S 57,590,033 56,886,057 703.976 (591,58)112,388
1214 P SSGCH
1215 DPW CIAC 53,575,515 51,103,623 2,471,892 2,471,892
1216 SCHMA T -SNP SNP 83,309.767 78,886,126 4,423,641 4,423,641
1217 P TROJD 1,572,028 1,483,047 88.981 88,981
1218 P SGCT 938,633 886,730 51,903 51,903
1219 SCHMAT-SE SE 27,051,042 25,331,266 1.719,776 (13,920)1,705.856
1220 P SG 20,901,884 19,750,504 1,151,380 2,850,82 4.002.222
1221 CUST CN
1222 SCHMAT-SO SO 23,130.941 21,883,647 1,247,294 14.506 1,261,800
1223 SCHMA T -SNP SNPD 5,136,011 4,899,043 236,968 236,968
1224 DPW BADDEBT
1225 P SSGCT
1226 BOOKDEPR SCHMDEXP 535.808,937 507.665,796 28,143,141 28,143,141
1227 B6 809,014.791 768.775,841 40,238.950 2.259,840 42,498,791
1228
1229 TOTAL SCHEDULE - M ADDITIONS 56 821,693.862 780,771,417 40,922,445 2,259,840 43,182,285
1230
REVISED PROTOCOL Page 2.20
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1231 SCHMDF Deductions - Flow Through
1232 SCHMDF S
1233 SCHMDF DGP
1234 SCHMDF DGU
1235 B6
1236 SCHMDP Deductions - Permanent
1237 SCHMDP S 904 904
1238 P SE 840,899 787,439 53,460 53,460
1239 PTD SNP 381,063 360,829 20.234 20,234
1240 SCHMDP IBT
1241 P SG
1242 SCHMDP-SO SO 26.365.079 24,943,390 1,421.689 1,421,689
1243 B6 27,587,945 26,092.562 1,495,383 1,495,383
1244
1245 SCHMDT Deductions - Temporary
1246 GP S 39,346,405 38,274,657 1.071,748 (915,314)156,434
1247 DPW BAD DEBT 1.168,170 1,122,860 45,310 45,310
1248 SCHMDT-SNF SNP 94,462,842 89,446.987 5,015,855 5,015.855
1249 SCHMDT CN 60,323 57,980 2,343 2,343
1250 SCHMDT SSGCH 68,842 65,091 3,751 3.751
1251 CUST DGP
1252 P SE 41,542,935 38.901,834 2,641,101 1,145,582 3,786,683
1253 SCHMDT -SG SG 135,152,429 127,707.560 7,444,869 46,711,480 54,156,349
1254 SCHMDT -GP~ GPS 82.386,340 77,943,807 4,442,533 4,442,533
1255 SCHMDT -SO SO 48,456,951 45,843,999 2,612,953 (1,054,008)1,558.944
1256 TAXDEPR TAXDEPR 1,622,113,173 1,539,894,065 82,219,108 82,219,108
1257 DPW SNPD 179,120 170,856 8,264 8,264
1258 B6 2,064,937,530 1,959,429,696 105,507,835 45.887,740 151,395,574
1259
1260 TOTAL SCHEDULE - M DEDUCTIONS B6 2.092,525,475 1,985,522,257 107,003,218 45,887,740 152,890.957
1261
1262 TOTAL SCHEDULE. M ADJUSTMENTS B6 (1,270,831,613 (66.080,773)109,708,672)
.1263
1264
1265
1266 40911 Stàte Income Taxes
1267 IBT IBT (22,619,435)(20,716,041 )(1,903,395)(1,724,556).(3,627,951)
1268 IBT SE
1269 PTC P SG (70,472)(70,472)
1270 IBT IBT
1271 Totl State Tax Expense (22,619,435)(20,716,041)(1,903,395)(1,795,029)(3,698,423)
1272
1273
1274 Calculation of Taxable Income:
1275 Operating Revenues 4.353,766,380 4,117,757,652 236,008,729 27,679,324 263,688,052
1276 Operating Deductions:
1277 o & M Expenses 2,676,130,329 2,511,613,702 164,516,627 19,262,722 183,779,349
1278 Deprciation Exnse 46,027,603 439,654,747 24.372,857 3,058,616 27,431,473
1279 Amortizaton Expense 43.698,570 41,447.110 2,251,459 (150,965)2,100,494
1280 Taxes Other Than Income 123,877,487 118.556,052 5.321,43 414,000 5,735,434
1281 Interest & Dividends (AFUDC-Equity)(63,955,322)(60,559,377)(3,395.945)160,217 (3,235,728)
1282 Misc Revenue & Expense (5,975,707)(5,678,965)(296,743)(284,193)(580,936)
1283 Total Operating Deducons 3,237,802,959 3,045,033,270 192,769,690 22,460,397 215,230,086
1284 Other Deductons:
1285 Interest Deductions 350,882,327 332,250,928 18,631,399 (423,149)18.208,250
1286 Interest on PCRBS
1287 Schedule M Adjustments (1,270,831,613)(1,204,750,840)(66,080,773)(43,627,899)(109,708,672)
1288
1289 Income Before State Taxes (505,750.519)(464,277,387)(41,473,133)(37,985.824)(79,458,956)
129
1291 State Income Taxes (22,619,435)(20,716,041)(1,903,395)(1,795,029)(3,698,423)
1292
1293 Total Taxble Income (483,131,084)(44,561,346)(39,569,738)(36,190.795)(75.760.533)
1294
1295 Tax Rate 35.0%35.0%35.0%35.0%35.0%
1296
1297 Fedral Income Tax - Calculated (169,095,879)(155,246,471 )(13,849,408)(12,666,778)(26,516,187)
1298
1299 Adjustments to CalCulated Tax:
130 40910 PMI P SE
1301 4010 REC P SG (3.821,447)(3,821,447)
1302 4010 P SO
1303 40910 IRSSltt LABOR S
130 Fedral Incme Tax Expnse (169,095,879)(155,246.471)(13,849.408)(16,488,225)(30,337,634)
130130 Totl Oprating Expees 3.59,784.94 3.386,745.857 204,039.088 20,803.097 224,842,185
REVISED PROTOCOL Page 2.21
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1307 310 Land and Land Rights
1308 p SG 2.329,517 2,201,196 128,321 128.321
1309 P SG 34,798,44 32,881,574 1,916,872 1,916,872
1310 P SG 56,303,435 53,201,961 3,101,474 3,101,474
1311 P S
1312 P SSGCH 2,448,255 2,314,873 133.382 133,382
1313 B8 95,879,653 90,599,605 5,280.048 5,280.048
1314
1315 311 Structures and Improvements
1316 p SG 234,107,411 221.211,609 12,895,802 12,895.802
1317 P SG 325,036,982 307,132,327 17,904,655 17,904,655
1318 P SG 221,770,821 209,554,580 12,216,241 12,216,241
1319 P SSGCH 57.386,063 54,259,652 3,126,411 3,126,411
1320 B8 838,301,276 792,158.167 46,143,109 46,143,109
1321
1322 312 Boiler Plant Equipment
1323 P SG 698,182,038 659,722,695 38,459.343 38,59,343
1324 P SG 658,624,890 622,344,552 36,280.338 36,280,338
1325 P SG 1,442,122,538 1,362,683,248 79,439.290 32,187,338 111,626,628
1326 P SSGCH 325,425,382 307,696.102 17,729.280 17,729,280
1327 B8 3,124,354.848 2,952,44,597 171,908.251 32,187,338 204,095,589
1328
1329 314 Turbogenerator Units
1330 P SG 139,149.055 131,484,032 7,665.023 7,665,023
1331 P SG 141,986.218 134,164,910 7,821,308 7,821,308
1332 P SG 487,922,642 461,045,433 26,877,209 26,877,209
1333 P SSGCH 63,734.933 60,262.633 3,472,300 3,472.300
1334 B8 832,792,848 786,957,009 45,835,839 45,835,839
1335
1336 315 Accessory Electic Equipment
1337 P SG 87,739,621 82,906,486 4,833,135 4,833,135
1338 P SG 138,674,494 131,035,612 7,638,882 7,638,882
1339 P SG 74,099,755 70,017,971 4,081,783 4,081,783
1340 P SSGCH 66,352,508 62,737,602 3,614,906 3,614,906
1341 B8 366.866,378 348,697,672 20,168,706 20.168,706
1342
1343
1344
1345 316 Mise Power Plant Equipment
1346 p SG 4,786,848 4,523,164 263,683 263,683
1347 P SG 5,245.086 4,956,160 288,925 288,925
1348 P SG 15,109,785 14,277,463 832,322 832,322
1349 P SSGCH 4,037,788 3,817,808 219,980 219,980
1350 B8 29,179,506 27.574,595 1.604,911 1.604.911
1351
1352 317 Steam Plant ARO
1353 P S
1354 B8
1355
1356 SP Unclassifed Steam Plant - Accunt 300
1357 P SG 787,304 743,936 43.369 43,369
1358 B8 787,304 743.936 43.369 43.369
1359
1360
1361 Total Steam Production Plant B8 5,288.161.813 4,997,177,580 290.984.233 32,187.338 323,171.572
1362
1363
1364 Summary of Steam Production Plant by Factor
1365 S
1366 DGP
1367 DGU
1368 SG 4.768.776,885 4.506,088,910 262.687,975 32,187.338 294,875,314
1369 SSGCH 519.384.929 491.088.670 28,296,258 28.296,258
1370 Total Steam Producton Plant by Factor 5.288.161.813 4.997,17.580 290,984,233 32,187.338 323,171,572
1371 320 Land and Land Rights
1372 P SG
1373 P SG
1374 B8
1375
1376 321 Strctres and Imprvements
1377 p SG
1378 P SG B8
1379
REVISED PROTOCOL Page 2.22
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1380
1381 322 Reactor Plant Equipment
1382 P SG
1383 P SG
1384 68
1385
1386 323 Turbogenerator Units
1387 P SG
1388 P SG
1389 68
1390
1391 324 Land and Land Rights
1392 P SG
1393 P SG
1394 68
1395
1396 325 Misc. Power Plant Equipment
1397 P SG
1398 P SG
1399 68
1400
1401
1402 NP Unclassified Nuclear Plant - Acct 300
1403 P SG
1404 68
1405
1406
1407 Totl Nuclear Production Plant B8
1408
1409
1410
1411 Summary of Nuclear Production Plant by Factor
1412 DGP
1413 DGU
1414 SG
1415
1416 Total Nuclear Plant by Factor
1417
1418 330 Land and Land Rights
1419 P SG 10.621.118 10.036.054 585.064 585.064
1420 P SG 5.270.019 4,979.720 290.299 290.299
1421 P SG 3.645.604 3.44.786 200.818 200.818
1422 P SG 672,873 635.808 37.065 37.065
1423 68 20,209,614 19,096,368 1,113,246 1.113.246
1424
1425 331 Structures and Improvements
1426 P SG 21.272,790 20.100.979 1,171.811 1.171.811
1427 P SG 5.299.236 5,007.327 291.908 291.908
1428 P SG 69,736,251 65.896,721 3,841.530 3.841.530
1429 P SG 7.984,198 7.544.388 439,809 439,809
1430 B8 104.294,475 98.549,416 5.745.059 5.745.059
1431
1432 332 Reservoirs, Dams & Waterways
1433 P SG 151.29.614 142.962,443 8.33.171 8.334.171
1434 P SG 20.156.916 19.046,572 1,110,34 1.110.343
1435 P SG 106.245.543 100.393.009 5.852.534 336.976 6.189.509
1436 P SG 37.108.148 35.064.047 2.044.102 2.044.102
1437 68 314.807.221 297.466.072 17.341.149 336.976 17.678.125
1438
1439 333 Water Wheel. Turbines, & Generaors
144 p SG 31.913.924 30,155.946 1,757.978 1,757.978
1441 P SG 8,828.84 8,342.508 486.337 486.337
1442 P SG 43.462.254 41.068,137 2.394.117 2.394,117
1443 P SG 27,234,682 25.734,460 1.500.222 1.500.222
144 68 111.439,704 105.301.050 6.138.654 6.138.654
144
144 334 Accssory Elec Equipment
1447 P SG 4.430,934 4.186,857 244.078 244,078
144 P SG 3.669.976 3.467,816 202.161 202.161
1449 P SG 43,817.031 41.403.370 2,413.660 2,413.660
1450 P SG 7,133,812 6.740,846 392.966 392.966
1451 B8 59.051.753 55,798.888 3.252.865 3,252,865
1452
REVISED PROTOCOL Page 2.23
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1453
1454
1455 335 Misc. Power Plant Equipment
1456 P SG 1,197,194 1.131,247 65,947 65,947
1457 P SG 186,194 175,938 10,257 10,257
1458 P SG 996,385 941,499 54,886 54,886
1459 P SG 11,353 10,728 625 625
1460 B8 2,391,127 2,259,411 131,715 131.715
1461
1462 336 Roads, Railroads & Bridges
1463 P SG 4,620,060 4,365,564 254,496 254,496
1464 P SG 828,931 783,269 45,662 45,662
1465 P SG 9,817,317 9,276,530 540,787 540,787
1466 P SG 682,347 644,760 37,587 37,587
1467 B8 15,948,654 15,070;123 878,531 878.531
1468
1469 337 Hydro Plant ARO
1470 P S
1471 B8
1472
1473 HP Unclassified Hydro Plant - Acct 300
1474 P S
1475 P SG
1476 P SG
1477 P SG
1478 B8
1479
1480 Total Hydraulic Production Plant B8 628,142,54 593,541,329 34,601,219 336,976 34,938,195
1481
1482 Summary of Hydraulic Plant by Factor
1483 S
1484 SG 628,142.548 593,541,329 34,601,219 336,976 34.938,195
1485 DGP
1486 DGU
1487 Total Hydraulic Plant by Factor 628,142,548 593,541,329 34,61,219 336,96 34,938,195
1488
1489 340 Land and Land Rights
1490 P SG 23,516,708 22,221,290 1,295,417 1,295,417
1491 P SG
1492 P SSGCT
1493 B8 23,516,708 22,221.290 1,295,417 1,295,417
1494
1495 341 Structures and Improvements
1496 P SG 151,043,941 142,723,688 8,320,252 8,320,252
1497 P SG 163,512 154.505 9,007 9,007
1498 P SSGCT 4.241,952 4,010,409 231.543 231,543
1499 B8 155,449,405 146.888,603 8,560,802 8,56.802
1500
1501 342 Fuel Holders, Proucers & Accssories
1502 P SG 8,406,209 7.943,153 463,056 463,056
1503 P SG 121,339 114,655 6,684 6.684
1504 P SSGCT 2,284,126 2,159,449 124,677 124,677
1505 B8 10,811,674 10.217,258 594,417 594,417
1506
1507 343 Prime Movers
1508 P S
1509 P SG 754,466 712.906 41,560 41,560
1510 P SG 2,223,358,082 2,100,884.449 122,473,634 13,942.359 136,415,992
1511 P SSGCT 51,744.608 48,920,181 2,824,427 2,824,427
1512 B8 2,275,857,156 2,150,517,536 125,339,620 13,942,359 139.281,979
1513
1514 344 Generators
1515 P S
1516 P SG
1517 P SG 331,535,449 313,272,825 18,262,623 18,262,623
1518 P SSGCT 15,873,643 15,007,197 866,447 866,447
1519 B8 347,409,092 328,280,022 19,129,070 19,129,070
REVISED PROTOCOL Page 2.24
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1520
1521 345 Accessory Electric Plant
1622 P SG 226.854,809 214.358.517 12,496,292 12,496,292
1623 P SG 156.586 147.961 8.626 8,626
1524 P SSGCT 2.919.649 2,760.283 159.366 159.366
1525 B8 229,931.044 217.266,760 12,664,284 12,664.284
1526
1527
1528
1529 346 Misc. Power Plant Equipment
1530 P SG 12.167.872 11,497.605 670.267 670.267
1531 P SG 11.813 11.162 651 651
1532 B8 12,179,685 11,508,767 670.918 670.918
1533
1534 347 Other Prouction ARO
1535 P S
1536 B8
1537
1538 OP Unclassified Other Prod Plant-Acct 300
1539 P S
1540 P SG
1541
1542
1543 Total Other Production Plant B8 3,055,154,764 2,886,900,236 168,254,528 13,942,359 182,196,887
1544
1545 Summary of Other Production Plant by Factor
1546 S
1547 DGU
1548 SG 2.978.090.785 2.814,042,716 164.048.069 13.942.359 177,990.427
1549 SSGCT 77.063,979 72.857.519 4.206.459 4,206.459
1550 Total of Other Production Plant by Factor 3,055.154.764 2.886.900.236 168.254,528 13,94.359 182.196,887
1551
1552 Experimental Plant
1553 103 Experimental Plant
1554 P SG
1555 Totl Experimental Production Plant 88
1556
1557 Total Production Plant B8 8,971,459,125 (1,417,619,144 493,839,981 46,46,673 54,306,653
1558 350 Land and Land Rights
1559 T SG 21,145.733 19.980,920 1.164.812 1.164.812
1560 T SG 48.501,155 45.829,470 2.671.685 2.671,685
1561 T SG 31,414,150 29.683.702 1.730.44 (23,847)1.706.601
1562 B8 101.061.037 95,94,092 5,566.945 (23,87)5,543.0Sl8
1563
1564 352 Strctures and Improvements
1565 T S
1566 T SG 7.741.60Sl 7.315.163 426.44 426.446
1567 T SG 18,157,495 17.157.28Sl 1,000.205 1.000.205
1568 T SG 59.577,575 56.295,746 3.281.829 3.281.829
1569 B8 85,476.679 80.768.1Sl8 4.708,481 4.708,481
1570
1571 353 Station Equipment
1572 T SG 129.985.618 122.825.3~3 7.160,255 7.160.255
1573 T SG 188.825.398 178,23.955 10.401,443 10,401,443
1574 T SG 988.384.505 933.93Sl,365 54.445.140 54.44.140
1575 B8 1.307.195,521 1.235.188.683 72.00.838 72,006.838
1576
1577 354 Towers and Fixtures
1578 T SG 156,322.773 147.711.736 8.611.037 8.611.037
1579 T SG 127.54.198 120.518,428 7.025.769 7.025.769
1580 T SG 165.062.634 155.970.163 9.092.472 9.092,472
1581 B8 44.929.605 424.200.327 24.729.278 24.729.278
1582
1583 355 Poles and Fixtures
1584 T SG 66.244.763 62.595.672 3.649.091 3,649.091
1585 T SG 117.745.408 111.259.405 6.486.003 6,486.003
1586 T SG 375.30.433 354.627.017 20.673,417 52.049.298 72.722.715
1587 88 55Sl.290.60 528,482.093 30.808.511 52.049.298 82.857.810
1588
REVISED PROTOCOL Page 2.25
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1589 356 Clearing and Grading
1590 T SG 197,260.339 186.394,257 10.866,082 10.866.082
1591 T SG 156.882,46 148.240.600 8.641.867 8.641.867
1592 T SG 380.070.379 359.134.210 20.936.169 20.936,169
1593 B8 734.213.185 693.769.067 40,444.118 40.44.118
1594
1595 357 Under9round Conduit
1596 T SG 6.371 6,020 351 351
1597 T SG 91,651 86.602 5.049 5.049
1598 T SG 3.113.807 2,942.283 171.524 171.524
1599 B8 3.211.828 3.034.905 176.923 176,923
1600
1601 358 Underground Conductors
1602 T SG
1603 T SG 1.087.552 1.027.644 59.908 59.908
1604 T SG 6,442.172 6.087.305 354.867 354.867
1605 B8 7.529.724 7.114.949 414.775 414.775
1606
1607 359 Roads and Trails
1608 T SG 1.863.032 1.760,406 102,625 102.625
1609 T SG 440.513 416.248 24.266 24.266
1610 T SG 9.151.569 8.647.455 504.114 504.114
1611 B8 11.455.113 10.824.109 631.005 631.005
1612
1613 TP Unclassified Trans Plant - Acc 300
1614 T SG 84.550.623 79.893.154 4.657,469 4.657,469
1615 B8 84.550.623 79.893.154 4.657,469 4.657,469
1616
1617 TSO Unclassified Trans Sub Plant - Acct 300
1618 T SG
1619 B8
1620
1621 Total Transmission Plant B8 3,342,913,921 3,158,769,577 184,144,34 52,025,451 236,169,795
1622 Summary of Transmission Plant by Factor
1623 DGP
1624 DGU
1625 SG 3.342.913.921 3.158.769.577 184.144.344 52,025,451 236.169.795
1626 Total Transmission Plant by Factor 3.342.913.921 3,158.769.577 184.144.344 52.025.51 236.169,795
1627 360 Land and Land Rights
1628 DPW S 51.856.326 50.519.585 1.336.741 1.336.741
1629 B8 51.856.326 50.519.585 1.336.741 1.336.741
1630
1631 361 Strctures and Improvements
1632 DPW S 66,495.517 65.02.256 1,493.261 1.493.261
1633 B8 66,495.517 65.002.256 1,493.261 1,493.261
1634
1635 362 Station Equipment
1636 DPW S 787.676.94 761.044.499 26.632.441 26.632,441
1637 B8 787.676.940 761.044,499 26.632.441 26.632,441
1638
1639 363 Storage Battery Equipment
1640 DPW S 1.457.805 1,457.805
1641 B8 1,457.805 1.457.805
1642
1643 364 Poles. Towers & Fixtures
1644 DPW S 903.958.177 842.950.744 61.007,433 61.007,433
1645 B8 903.958.177 842.950.744 61.007.433 61,007,433
164
1647 365 Overhead Conducors
164 DPW S 631.378.730 597.455.532 33.923.198 33.923.198
1649 B8 631.378.730 597.455.532 33.923.198 33.923.198
1650
REVISED PROTOCOL Page 2.26
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1651 366 Underground Conduit
1652 DPW S 290,621,174 283,247,994 7.373,179 7,373.179
1653 B8 290,621,174 283,247,994 7.373,179 7,373,179
1654
1655
1656
1657
1658 367 Underground Conductors
1659 DPW S 697,799,779 674,120,851 23,678,928 23,678,928
1660 B8 697,799,779 674,120,851 23.678,928 23.678,928
1661
1662 368 Line Transformers
1663 DPW S 1,056,509,849 990,583,151 65,926,697 65.926,697
1664 B8 1,056,509,849 990,583,151 65,926,697 65,926,6\17
1665
1666 369 Services
1667 DPW S 559,763,102 531,874,191 27,888,911 27,888,911
1668 B8 559,763,102 531,874,191 27.88,911 27,888,911
1669
1670 370 Meters
1671 DPW S 187,209,616 173,388,196 13,821,420 13,821,420
1672 B8 187,209,616 173,388,196 13,821,420 13,821,420
1673
1674 371 Installations on Customers' Premises
1675 DPW S 8,809,120 8,644,004 165.115 165,115
1676 B8 8,809,120 8,644,004 165,115 165,115
1677
1678 372 Leased Property
1679 DPW S
1680 B8
1681
1682 373 Street Lights
1683 DPW S 62,885,404 62,283,269 602,135 602,135
1684 B8 62,885,404 62,283,269 602,135 602,135
1685
1686 DP Unclassified Dist Plant - Acct 300
1687 DPW S 20,216.252 19.291,256 \124,997 924,997
1688 B8 20,216,252 19,291,256 924,997 924,997
1689
1690 DSO Unclassified Dist Sub Plant. Acct 300
1691 DPW S
1692 B8
1693
1694
1695 Totl Distribution Plant B8 5,326,637,791 5,061,863,333 264,774,45 264,774,458
1696
1697 Summary of Distnbution Plant by Factor
1698 S 5,326,637,791 5,061,863,333 264,774,458 264,774,458
1699
1700 Total Distnbution Plant by Factor 5,326,637, 791 5,061,863,333 264,774,458 264.774,458
REVISED PROTOCOL Page 2.27
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAl
1701 389 Land and Land Ri9hts
1702 G-SITUS S 9,472,275 9,274,636 197,639 197,639
1703 CUST CN 1,128,506 1,084,668 43,838 43,838
1704 PT SG 332 314 18 18
1705 G-SG SG 1,228 1,160 68 68
1706 PTO SO 5.598,055 5,296,190 301,865 301,865
1707 88 16,200,395 15,656,968 543,27 543,427
1708
1709 390 Structures and Improvements
1710 G-SITUS S 111,200,704 101,422,380 9,778,324 9,778,324
1711 PT SG 358,127 338,400 19,727 19,727
1712 PT SG 1,653,732 1,562,636 91,096 91,096
1713 CUST CN 12,319,587 11,841,025 478,563 478,563
1714 G-SG SG 3,675,782 3,473,302 202,480 202,480
1715 PTD SO 102,313,681 96,796,602 5,517,078 5,517,078
1716 88 231,521,614 215,434.345 16,087,269 16,087,269
1717
1718 391 Offce Furniture & Equipment
1719 G-5ITUS S 13.065,614 12.137,233 928,381 928,381
1720 PT SG 1,046 988 58 58
1721 PT SG 5,295 5,003 292 292
1722 CUST CN 8,685,337 8,347.949 337,388 337,388
1723 G-SG SG 4,784,588 4,521,029 263,559 263,559
1724 P SE 97,829 91.609 6,219 6,219
1725 PTO SO 54,551,124 51,609.554 2,941,570 2.941,570
1726 G-SG SSGCH 74,351 70,301 4.051 4,051
1727 G-SG SSGCT
1728 B8 81,265,184 76,783,667 4,481,517 4,481,517
1729
1730 392 Transporttion Equipment
1731 G-5ITUS S 73,113,164 68,190,669 4,922,495 4,922,495
1732 PTD SO 7.996,779 7,565,567 431,212 431.212
1733 GcSG SG 17,254,817 16,304,336 950.481 950,481
1734 CUST CN
1735 PT SG 838,181 792,010 46,171 46.171
1736 P SE 404,148 378,454 25,694 25,694
1737 PT SG 120,286 113,660 6.626 6,626
1738 G-5G SSGCH 374,178 353.793 20,385 20,385
1739 PT SSGCT 44,655 42,218 2,437 2,437
1740 88 100,146,208 93.740,707 6,05,501 6.40,501
1741
1742 393 Stores Equipment
1743 G-SITUS S 8,861,339 8,312.757 54,582 548,582
1744 PT SG 108,431 102,458 5,973 5,973
1745 PT SG 360,063 340,229 19,834 19,834
1746 PTO SO 445,293 421,281 24,012 24,012
1747 G-SG SG 4,062,155 3,838.392 223,764 223,764
1748 PT SSGCT 53,971 51,025 2.946 2,946
1749 88 13,891,252 13,066,141 825,110 825.110
REVISED PROTOCOL Page 2.28
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1750
1751 394 Tools, Shop & Garage Equipment
1752 G-SITUS S 32.024.394 30.281.765 1.742,629 1.742,629
1753 PT SG 2.120.983 2.004.148 116.834 116.834
1754 G-SG SG 20,499.259 19.370.058 1.129.201 1.129.201
1755 PTO SO 3.986.801 3.771.820 214.981 214.981
1756 P SE 7.106 6.655 452 452
1757 PT SG 2.176,302 2.056,20 119,882 119.882
1758 G-SG SSGCH 1.716.105 1,622.611 93,494 93,494
1759 G-SG SSGCT 89.913 85.006 4.908 4,908
1760 68 62.620,863 59.198,483 3,422.381 3,422,381
1761
1762 395 Laboratory Equipment
1763 G-SITUS S 25,228.787 23,956,655 1,272,132 1.272,132
1764 PT SG 20.622 19,486 1,136 1,136
1765 PT SG 13.281 12.550 732 732
1766 PTO SO 5,197.970 4.917,679 280.291 280,291
1767 P SE 7.593 7.111 483 483
1768 G-SG SG 6.353,527 6,003.543 349.984 349,984
1769 G-SG SSGCH 253.001 239.217 13.784 13.784
1770 G-SG SSGCT 14,022 13.256 765 765
1771 68 37,088.802 35.169.496 1.919,306 1.919,306
1772
1773 396 Power Operated Equipment
1774 G-SITUS S 94.279.509 87.117.887 7.161.622 7.161.622
1775 PT SG 845.108 798.555 46.553 46.553
1776 G-SG SG 31.633.038 29.890.533 1.742,505 1.742.505
1777 PTD SO 1,410,640 1.334.574 76.066 76.066
1778 PT SG 1.664,492 1,572.804 91,689 91.689
1779 P SE 73,823 69.130 4,693 4,693
1780 P SSGCT
1781 G-SG SSGCH 968.906 916.120 52,786 52,786
1782 68 130.875.517 121.699,602 9,175.915 9.175.915
1783 397 Communication Equipment
1784 COM_EO S 101.721,635 96.539.236 5.182.399 5,182.399
1785 COM_EO SG 4.816,644 4.551.319 265.325 265.325
1786 COM_EO SG 9,615,788 9,086.102 529.685 529.685
1781 COM_EO SO 48.166.011 45,568,153 2,597.265 2.597.265
1788 COM_EO CN 2.641.488 2.538.818 102.610 102.610
1789 COM_EO SG 14.202.015 10.114,598 4.081,416 4.087,416
1790 COM_EO SE 114,538 101.256 1.282 1.282
1791 COM_EO SSGCH 1,055,756 998,238 57.518'57,518
1792 COM_EO SSGCT 1,590 1.503 81 87
1793 68 242.335,411 229,505.884 12.829.587 12,829.587
1794
1795 398 Misc. Equipment
1796 G-SITUS S 1.354,146 1.290,393 64.352 64.352
1791 PT SG
1798 PT SG 1,997 1,861 110 110
1799 CUST CN 199,165 192.005 7.160 1,160
1800 PTO SO 3.316,792 3.194.704 182.087 182,087
1801 P SE 1,668 1.562 106 106
1802 G-SG SG 1,865,540 1,162.777 102,163 102,763
1803 G-G SSGCT
1804 68 6.800,507 6.443.328 357.179 357.179
1805
180 399 Coal Mine
1807 P SE 278.021.722 260,346.431 17,675.291 13,146,472 30.821.763
180 MP P SE
180 68 278.021,722 260.346.431 17.675,291 13.146,472 30.821.163
1810
1811 399L WIDCO Capital Lease
1812 P SE B8
1813
1814
1815 Remove Capitl Leases
1816 68
1817
REVISED PROTOCOL Page 2.29
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1818 1011390 General Capital Leases
1819 G-SITUS S 18.984.156 18,984,156
1820 P SG 16.951,793 16.018,004 933,789 933,789
1821 PTD SO 12,664,054 11,981,168 682.886 682,886
1822 89 48,600,002 46,983.327 1.616,675 1,616,675
1823
1824 Remove Capital Leases (48.600.002)(46.983,327)(1,616,675)(1.616,675)
1825
1826
1827 1011346 General Gas Line Capital Leases
1828 P SG
1829 89
1830
1831 Remove Capitl Leases
1832
1833
1834 GP Unclassified Gen Plant - Acct 300
1835 G-SITUS S
1836 PTD SO 4,694.044 4,440.926 253,118 253,118
1837 CUST CN
1838 G-SG SG
1839 PT SG
1840 PT SG
1841 88 4,694,044 4,440,926 253,118 253,118
1842
1843 399G Unclassified Gen Plant - Acet 300
1844 G-SITUS S
1845 PTD SO
1846 G-SG SG
1847 PT SG
1848 PT SG
1849 88
1850
1851 Total General Plant B8 1,205,461,579 1.131,485,978 73,975,601 13,146,472 87,122,073
1852
1853 Summary of General Plant by Factor
1854 S 489,306,322 457,507,766 31.798,556 31.798,556
1855 DGP
1856 DGU
1857 SG 206,004,452 194,656,701 11,347.751 11,347,751
1858 SO 250,401.250 236.898,819 13,502,430 13,502,430
1859 SE 278.728,427 261,008.207 17,720,220 13,146,472 30,866,692
1860 CN 24,974.683 24,004.525 970,158 970,158
1861 DEU
1862 SSGCT 204,151 193,008 11.143 11,143
1863 SSGCH 4.442,297 4,200.279 242,018 242,018
1864 Less Capital Leases (48.60.002)(48,983.327)~1.616,675)t616.675)1865 Total General Plant by Factor 1.205,461.579 1,131.485,978 3.975.601 13,146,472 7.122.073
1866 301 Organization
1867 I-SITUS S
1868 PTD SO
1869 l-SG SG
1870 B8
1871 302 Franchise & Consent
1872 1-SITUS S 1,000.000 1,000.000 1,000,000
1873 I-SG SG 9,402,471 8.884.536 517,935 517.935
1874 l-SG SG 99,510,474 94.028,942 5.481,532 5,481,532
1875 l-SG SG 9,240,742 8,731,716 509.026 509,026
1876 P SG
1877 P SG 600.993 567.887 33,106 .33.106
1878 88 119,754.679 112.213,080 7.541.599 7.541.599
1879
REVISED PROTOCOL Page 2.30
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1880 303 Miscellaneous Intangible Plant
1881 1-SITUS S 6,042,837 5,626,978 415,859 415,859
1882 I-SG SG 95.041,256 89,805,910 5,235,346 631,847 5,867,193
1883 PTD SO 366,513,585 346,750.009 19,763,576 19,763,576
1884 P SE 3,453,872 3,234.291 219,581 219,581
1885 CUST CN 118,758,961 114,145,691 4,613,271 4,613,271
1886 P SG
1887 P SSGCT
1888 B8 589,810.510 559,562.878 30,247,632 631,847 30,879,479
1889 303 Less Non-Utilty Plant
1890 I-SITUS S
1891 589,810,510 559,562,878 30.247,632 631,847 30,879,479
1892 IP Unclassified Intangibie Plant - Acet 300
1893 I-SITUS S
1894 I-SG SG
1895 P SG
1896 PTD SO
1897
1898
1899 Total Intangible Plant B8 709,565,190 671,775,959 37,789,231 631,847 38.421,078
1900
1901 Summary of Intangible Plant by Factor
1902 S 7,042.837 5,626,978 1,415.859 1,415,859
1903 DGP
1904 DGU
1905 SG 213,795,935 202,018,990 11,776.945 631,847 12,408.792
1906 SO 366,513,585 346,750,009 19.763,576 19,763,576
1907 CN 118,758,961 114,145.691 4,613,271 4,613,271
1908 SSGCT
1909 SSGCH
1910 SE 3,453,872 3,234,291 219,581 219.581
1911 Total Intangible Plant by Factor 709.565,190 671,775.959 37,789,231 631,847 38,421,078
1912 Summary of Unclassified Plant (Account 106)
1913 DP 20,216.252 19,291,256 924,997 924,997
1914 DSO
1915 GP 4,694,044 4,44,926 253,118 253,118
1916 HP
1917 NP
1918 OP
1919 TP 84,550,623 79,893,154 4.657,469 4,657,469
1920 TSO
1921 IP
1922 MP
1923 SP 787,304 743,936 43.369 43,369
1924 Total Unclassified Plant by Factor 110,248,224 104,369.271 5,878,952 5.878,952
1925
1926 Total Elecric Plant In Service B8 19.556,037.605 18,501.513,991 1,054.523.614 112,270,443 1.166,794.057
REVISED PROTOCOL Page 2.31
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1927 Summary of Electric Plant by Factor
1928 S 5.822.986.950 5,524.998,077 297.988,873 297.988.873
1929 SE 282,182,299 264,242,498 17,939,801 13,146,472 31.086.273
1930 DGU
1931 DGP
1932 SG 12.137.724.526 11,469,118.223 668,606.302 99,123,971 767,730,274
1933 SO 616.914.834 583,648,828 33.266.00f,33,266.006
1934 CN 143.733.644 138.150.216 5,583,429 5.583,429
1935 DEU
1936 SSGCH 523.827,225 495.288.949 28.538.276 28,538,276
1937 SSGCT 77,268.130 73.050.527 4.217,603 4.217.603
1938 Less Capital Leases (48,600,002)(46.983.327)~1.616,675)(1.616.675)
1939 19,556.037,605 18,501.513.991 1.0 4,523,614 112.270,443 1,166.794.057
1940 105 Plant Held For Future Use
1941 DPW S 3,473,204 3,473,204
1942 P SG
1943 T SG 325,029 307.125 17,904 (509.444)(491,540)
1944 P SG 8,923,302 8,31.762 491,540 491.540
1945 P SE 953,014 892,426 60.588 (60.588)
1946 G SG
1947
1948
1949 Total Plant Held For Future Use B10 13,674,549 13,104,516 570,02 (570,02)(0)
1950
1951 114 Electric Plant Acquisition Adjustments
1952 P S
1953 P SG 142.633.069 134.776.129 7,856,940 7.856,940
1954 P SG 14.560.711 13.758,634 802,076 802.076
1955 Total Electric Plant Acquisition Adjustment B15 157,193,780 148,534,764 8,659,016 8,659.016
1956
1957 115 Accum Provision for Asset Acquisition Adjustments
1958 P S
1959 P SG (4.632,686)(4,632,686)
1960 P SG (673,478)673,478)
1961 615 6,6.164
1962
1963 120 Nuclear Fuel
1964 P SE
1965 Total Nuclear Fuel B15
~966
1967 124 Weatherization
1968 DMSC S 2,633.178 2,599.959 33.220 33,220
1969 DMSC SO t,454)(4,214)(240)(240)
1970 616 2.6 8.725 2,595,745 32.980 32,980
1971
1972 182W Weatherization
1973 DMSC S 34,729,463 31.258,802 3,470,661 3,470,661
1974 DMSC SG
1975 DMSC SGCT
1976 DMSC SO
1977 616 34.729,463 31,258,802 3,470,661 3,470,661
1978
1979 186W Weatherizaton
1980 DMSC S
1981 DMSC CN
1982 DMSC CNP
1983 DMSC SG
1984 DMSC SO
1985 616
1986
1987 Total Weatherization B16 37.358.188 33,854.547 3,503.64 3.503.64
REVISED PROTOCOL Page 2.32
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1988
1989 151 Fuel Stock
1990 P DEU
1991 P SE 158.860.196 148.760.625 10.099.571 1.839.370 11.938.941
1992 P SSECT
1993 P SSECH 12.069.947 11.343.216 726.731 (258.156)468.575
1994 Total Fuel Stock B13 170,930,143 160,103,840 10,826,302 1,581,214 12,407,516
1995
1996 152 Fuel Stock - Undistributed
1997 P SE
1998
1999
2000 25316 DG&T Working Capital Deposit
2001 P SE (1.379.000)(1.291.330)(87.670)(56,073)(143,744)
2002 613 (1.379.000)(1.291,330)(87.670)(56.073)(143,744)
2003
2004 25317 DG&T Working Capital Deposit
2005 P SE (1.758.544)(1.646.744)(111.800)(5,907)(117.706)
2006 613 (1.758,544)(1..646,744)(111.800)(5,907)(117.706)
2007
2008 25319 Provo Working Capital Deposit
2009 P SE
2010
2011
2012 Total Fuel Stock 613 167.792.599 157.165,766 10.626.832 1,519.234 12,146,067
2013 154 Materials and Supplies
2014 MSS S 86,919,683 82.030,372 4.889,311 4,889,311
:2015 MSS SG 3,082,186 2,912,404 169,782 169.782
2016 MSS SE 4.170,119 3,905.003 265,116 265.116
2017 MSS SO 253,641 239,964 13,677 13.677
2018 MSS SNPPS 81,516,215 77.032.219 4,463.997 4,483.997
2019 MSS SNPPH (1,860)(1,757)(102)(102)
2020 MSS SNPD (3.081.941 )(2.939.745)(142.196)(142.196)
2021 MSS SNPT
2022 M$S SG
2023 MSS SG
2024 MSS SSGCT
2025 MSS SNPPO 5,288,978 4,997.690 291.288 291,288
2026 MSS SSGCH
2027 Total Materials and Supplies B13 178,147,022 168,176,149 9,970,873 9,970,873
2028
2029 163 Stores Expense Undistributed
2030 MSS SO
2031
2032 613
2033
2034 25318 Provo Working Capital Deposit
2035 MSS SNPPS (273,000)(257,983)(15.017)(15.017)
2036
2037 613 (273,000)(257,983)(15.017)(15.017)
2038
2039 Total Materials & Supplies 613 177,874,022 167,918.166 9.955,856 9.955,856
2040
2041 165 Prepayments
2042 DMSC S 2,934,455 2.770.438 164,017 164,017
2043 GP GPS 9.858.973 9.327,346 531.627 531,627
2044 PT SG 6,415.547 6.062,146 353.400 353.400
2045 P SE 7.102,118 6.650.600 451,519 451.519
2046 PTD SO 19.839.36 18,769,559 1,069.801 1,069,801
2047 Total Prepaymnts B15 46,150,453 43,580,089 2,570,364 2,570,364
2048
REVISED PROTOCOL Page 2.33
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2049 182M Misc Regulatory Assets
2050 DDS2 S 56,142,627 56,331.298 (188.671)(17,580)(206,251)
2051 DEFSG SG 2,654.642 2,508,411 146.231 146,231
2052 P SGCT 8.511.723 8.041.060 470,663 470.663
2053 DEFSG SG-P 74,434 74,434
2054 P SE 74.327 74,327
2055 P SSGCT
2056 DDS02 SO 7,516,382 7,111,075 405.307 405,307
2057 B11 74,825,374 73.991,844 833,530 131.181 964,71
2058
2059 186M Misc Deferred Debits
2060 LABOR S 16.240,410 16,240,410
2061 P SG
2062 P SG
2063 DEFSG SG 38,988,960 36,841,254 2,147,706 531,032 2,678,738
2064 LABOR SO 16,926 16.014 913 913
2065 P SE 10.045.914 9,407,242 638,671 (108,911)529,760
2066 P SNPPS
2067 GP EXCTAX
2068 Total Misc. Deferred Debits 811 65,292,210 62,5õ4,920 2,787,290 42,121 3,209,411
2069
2070 Working Capital
2071 CWC Cash Working Capital
2072 CWC S 36,075,418 34,127,309 1,948,109 18,016 1,966,125
2073 CWC SO
2074 CWC SE
2075 814 36,075,18 34,127.309 1,948.109 18,016 1.966.125
2076
2077 OWC Ot Work. Cap.
2078 131 Cas GP SNP
2079 135 Working Fun GP SG 1.920 1,814 106 106
2080 141 Noles Recivab GP SO 540,572 511,422 29,149 29.149
2081 143 Other AI GP SO 33,985,372 32,152,773 1,832,599 1,832,599
2082 232 NP PTD S
2083 232 NP PTD SO (4,215.163)(3,987,868)(227,295)(227,295)
2084 232 NP P SE (1.408,97)(1,318,951 )(89,545)(89,545)
2085 232 NP T SG
2086 2533 O'he_. Of. oro. P S
2087 2533 OUie Msc. Of. Crd. P SE (6,046.034)(5,661,656)(38,378)(384,378)
2088 230 Ast Retir. Oblig.P SE (2,415,872)(2,262,283)(153,590)(153,590)
2089 230 As ReÍir. Oblig. P S
2090 254105 ARO RO L_Uy P S
2091 254105 ARO Re L_Uy P SE (716,594)(671.036)(45,558)(45,558)
2092 2533 Chla Reamtin P SSECH
2093 814 19,725,703 18,764.215 961.489 961,489
2094
2095 Total Working Capital 814 55,801,121 52,891,524 2,909,597 18,016 2,927,613
2096 Miscellaneous Rate Base
2097 18221 Unre Plant & Reg Study Costs
2098 P S
2099
2100 B15
2101
2102 1822 Nuclear Plant - Trojan
2103 P S (372,363)(372,363)
2104 P TROJP 885.265 835.358 49.907 49,907
2105 P TROJD 1,296,271 1,222.899 73,372 73,372
2106 B15 1.809,172 1,685.894 123,279 123,279
2107
2108
REVISED PROTOCOL Page 2.34
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2109
2110 1869 Misc Deferred Debit$-Trojan
2111 P 5
2112 P SNPPN
2113 B15
2114
2115 Total Miscellaneous Rate Base B15 1,809,172 1,685,894 123,279 123,279
2116
2117 Total Rate Base Additions B15 701,44,594 664,211,320 37,233,274 1,52,520 38,753,793
2118 235 Customer Service Deposits
2119 CUST 5
2120 CUST CN
2121 Total Customer Service Deposits B15
2122
2123 2281 Prop Ins PTD SO
2124 2282 Inj& Dam PTD SO (7,487.871)(7.084,101)(403.770)(403.770)
2125 2283 Pen & Ben PTD SO (22,725.860)(21.500.410)(1.225.451 )(1,225.451 )
2126 254 Reg Liab PTD SG
2127 254 Reg Liab PTD SE (1.217.286)(1.139.897)(77,389)77.389
2128 254 Ins Prov PTD SO (109.564)(103.6561 (5.9081 (5.908)
2129 B15 (31.540.581)(29,828,06~(1.712.518 77.389 (1.635.128)
2130
2131 22841 Accum Misc Oper Provisions - Other
2132 P 5
2133 P SG
l1.500.000i ll,417.3731 l82,627)
(82.627)
2134 B15 1,500.000 1,417.373 82.627)(82.627)
2135
2136 22842 Prv-Trojan P TROJD
2137 230 ARO P TROJP (1,711.281)(1.614.808)(96,473)(96,473)
2138 254105 ARO P TROJP (3,608,947)(3,405,494)(203,453)(203.453)
2139 254 P S ~6,O09,324l . (6,009.3241
2140 815 (1,329,552 (11.029,626 (299.926)(299.926)
2141
2142 252 Customer Advances for Construction
2143 DPW 5 (13,473.111)(13.198,024)(275.088)6,822 (268,266)
2144 DPW SE
2145 T SG (7,471,547)(7.059.977)(411,570)(267,861)(679,431)
2146 DPW SO
2147 CUST CN
(686,658)2148 Total Customer Advances for Constrction 819 (20,944,658)(20,258,001)(261,039)(94,697)
2149
2150 25398 502 Emissions
2151 P SE (2.100,793)
i2,1oo,793)2152 B19 (2.100,793)2.100.793)
2153
2154 25399 Other Deferrd Credits
2155 P 5 (3.803.740)(3.728,560)(75.180)(75.180)
2156 LABOR SO (181.285)(181,285)
2157 P SG (7,567.103)(441.134)(441.134)
2158 P SE (1.108.081)(75,229)75.229)
2159 B19 1 ,.4 5 .5
REVISED PROTOCOL Page 2.35
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2160
2161 190 Accumulated Deferrd Income Taxes
2162 P S 10,695.484 10,695,486 (2)(2)
2163 CUST CN 65,488 62,944 2,54 2,544
2164 P IBT
2165 LABOR SO 36,90,690 34,522,996 1,967,694 (49,961)1,917,732
2166 P DGP
2167 CUST BADDEBT 3,345,135 3,215.387 129,748 129,748
2168 P TROJD 1,332,481 1,257,059 75,422 75,422
2169 P SG 39,391,566 37,221,682 2,169.884 (2,002,880)167.004
2170 P SE 3,097,022 2,900,128 196,894 (461,730)(264,837)
2171 PTD SNP
2172 DPW SNPD 703,493 671,035 32,458 32,458
2173 P SSGCT
2174 Total Accum Deferred Income Taxes B19 95,121,359 90,546,718 4,574,641 (2,514,572)2,060,069
2175
2176 281 Accumulated Deferred Income Taxes
2177 P S
2178 PT DGP
2179 T SNPT
2180 B19
2181
2182 282 Accumulated Deferred Income Taxes
2183 GP S (138,317,516)(138,317,516)
2184 ACCMDIT DITBAL (2,336,392,077 (2,195,736.556)(140,655,521 )140,655.521 0
2185 P SSGCH
2186 LABOR SO (6.909,549)(6,536,964)(372,585)6,813 (365.772)
2187 CUST CN
2188 P SE (5.607.614)(5,251,109)(356.505)(234,572)(591,078)
2189 P SG (5,705,530)(5,391.241)(314,289)(16,482,797)(16,797,086)
2190 B19 (2,354,614,770)(2,212,915,870)(141,698,900)(14,372,551 )(156,071,451 )
2191
2192 283 Accumulated Deferred Income Taxes
2193 GP S (30,884,504)(29,777,409)(1,107,095)1,028,227 (78,868)
2194 P SG (6,716,785)(6,346,791)(369,994)(41,055)(411,48)
2195 P SE (4,844,933)(4,536,915)(308,018)41,333 (266,685)
2196 LABOR SO (16.761,723)(15,857,878)(903,845)710,717 (193,128)
2197 GP GPS (5.687,055)(5,380.391 )(306,664)(306,664)
2198 PTD SNP "(5,228,914)(4,951,265)(277,649)(277,649)
2199 P TROJD.
2200 P SSGCT
2201 P SGCT (2,701,338)(2,551,965)(149,373)(149.373)
2202 P SSGCH
2203 B19 (72,825,252)(69,402,615)(3,422,637)1,739,222 (1,683,15)
2204
2205 Totl Accum Deferred Income Tax B19 (2,332,318,663)(2,191,771,766)(140,546,897)(15,147,900)(155,694,797)
2206 255 Accumulated Investment Tax Credit
2207 PTD S
2208 PTD 1TC84 (1,745,297)(1,745,297)
2209 PTD ITC85 (3,044.242)(3,044,242)
2210 PTD ITC86 (1,479,759)(1,479,759)
2211 PTD ITC88 (222.246)(222,246)
2212 PTD ITC89 (486,772)(486,772)
2213 PTD ITC90 (315,906)(271,738)(44,168)(44,168)
2214 PTO IBT .
f82,102)
(182,102l
2215 Total Accumlated ITC B19 (7,294,222)(7.250,054)(44.168)182,102)(226,270
2216
2217 Total Rate Base Deducions (2,417,922,963)(2,273,958,626)(143,964,337)(17,795,730)(161,760,067)
2218
REVISED PROTOCOL Page 2.36
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT AOJTOTAL
2219
2220
2221 108SP Steam Prod Plant Accumulated Depr
2222 P S
2223 P SG (828,531,539)(782,891,896)(45,639,643)(45,639,643)
2224 P SG (936,120,976)(884,554,772)(51,566,204)(51,566,204)
2225 P SG (552.789,110)(522,338.733)(30,450,377)(761,613)(31.211,990)
2226 P SSGCH (158.685,661 )(150,040,415)(8.645.246)(8,645,246)
2227 817 (2,476.127.286)(2,339,825.817)(136,301,470)(761,613)(137,063,083)
2228
2229 108NP Nuclear Prod Plant Accumulated Depr
2230 P SG
2231 P SG
2232.P SG
2233 817
2234
2235
2236 108HP Hydraulic Prod Plant Accum Depr
2237 P S
2238 P SG (150,429.735)(142,143,316)(8.286,419)(8,286,19)
2239 P SG (28,604.226)(27,028.563)(1.575,663)(1,575,663)
2240 P SG (59,853.861)(56,556,813)(3.297,049)(70,857)(3.367.906)
2241 P 5G (12,861,842)(12,153.348)(708.494)(72.398)(780,893)
2242 817 (251,749,664)(237.882.039)(13.867.625)(143.255)(14.010.880)
2243
2244 1080P Other Production Plant - Accum Depr
2245 P S
2246 P SG (1.347,482)(1,273,256)(74,226)(74,226)
2247 P SG
2248 P 5G (263,762.956)(249,233.579)(14.529.377)(565,003)(15.094,38)
2249 P S5GCT (19.564.578)(18,496,665)(1.067.913)(1.067,913)
2250 817 (284,675,015)(269,003.500)(15.671.516)(565.003)(16.236.519)
2251
2252 108EP Experimental Plant- Accum Depr
2253 P SG
2254 P SG
2255
2256
2257 Totl Prouction Plant Accum Depreciation B17 (3.012.551,966)(2,846,711.356)(165,84,610)(1,469,872)(167,310,482)
2258
2259 Summary of Pro Plant Depreciation by Factor
2260 5
2261 DGP
2262 DGU
2263 5G (2.834.301,727)(2,678,174,275)(1,489,872)(157,597,324)
2264 55GCH (158.685,661)(150.040,415)(8.645.246)
2265 55GCT 19.564.578)18.496,665)1,067,913)
2266 Total of Prod Plant Depreciation by Factor ,71 .1.1 0,482
2267
2268
2269 108TP Transmission Plant Accumulated Depr
2270 T 5G (36,532,026)(21,367,43)
2271 T 5G (366,312,895)(21,354,659)
2272 T 5G (347.041,141)20.231,189)
2273 Totl Trans Plant Accum Pepreciation B17 ,79,
REVISED PROTOCOL Page 2.37
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2274 108360 Land and Land Rights
2275 DPW S (5.731.126)(5,471.879)(259.247)(259.247)
2276 817 (5.731.126)(5,71.879)(259.247)(259.247)
2277
2278 108361 Structures and Improvements
2279 DPW S (13.581.278)(13.138,03)(442.875)(442.875)
2280 817 (13.581.278)(13.138,03)(442.875)(442.875)
2281
2282 108362 Station Equipment
2283 DPW S (207.834.133)( 198.557.095)(9.277.038)(9.277.038)
2284 817 (207.834.133)(198.557.095)(9.277.038)(9.277.038)
2285
2286 108363 Storage 8attery Equipment
2287 DPW S (775.263)(775.263)
2288 B17 (775.263)(775.263)
2289
2290 108364 Poles. Towers & Fixtures
2291 DPW S (472,497,456)(438.618.489)(33.878.967)(33.878.967)
2292 817 (472,497,456)(438.618.489)(33.878.967)(33.878,967)
2293
2294 108365 Overhead Conductors
2295 DPW S (257.576.586)(247.145.604)(10.430.983)(10,30.983)
2296 817 (257.576.586)(247.145.604)(10.430.983)(10,430.983)
2297
2298 108366 Underground Conduit
2299 DPW S (121,003,027)(117,701.126)(3.301.901 )(3.301.901 )
2300 817 (121.003.027)(117,701.126)(3.301.901)(3,301.901 )
2301
2302 108367 Underground Conductors
2303 DPW S (279.736.871 )(268.973.545)(10.763.326)(10.763.326)
2304 B17 (279.736.871 )(268.973.54)(10.763.326)(10.763.326)
2305
2306 108368 Line Transformers
2307 DPW S (361.323.647)(337.660,494)(23.663.153)(23.663.153)
2308 817 (361.323.647)(337.660,494)(23.663.153)(23,663.153)
2309
2310 108369 Services
2311 DPW S (163.299.910)(152.868.799)(10.431.110)(10.431.110)
2312 817 (163.299.910)(152.868.799)(10.431.110)(10.431.110)
2313
2314 108370 Meters
2315 DPW S (84.175.634)(75.808.861)(8.366.773)(8,36.773)
2316 817 (84.175.634)(75.808,861 )(8,366,773)(8.366.773)
2317
2318
2319
2320 108371 Installations on Customers' Premises
2321 DPW S (7.84.403)(7.709,414)(136.989)(136,989)
2322 817 (7.846.403)(7.709.414)(136.989)(136.989)
2323
2324 108372 Leased Propert
2325 DPW S
2326 817
2327
2328 108373 Stret Lights
2329 DPW S (28.660.733)(28.170.544)(490.188)(490.188)
2330 817 (28,660.733)(28.170.544)(490.188)(490.188)
2331
2332 108000 Unclassified Dist Plant - Acet 300
2333 DPW S
2334 817
2335 '
2336 108DS Unclassified Dlst Sub Plant - Acet 300
2337 DPW S
2338 B17
2339
2340 108DP Unclssifed Dist Sub Plant - Acet 300
2341 DPW S 730.582 729.334 1.248 1.248
2342 B17 730.582 729.334 1.248 1,248
2343
2344
2345 Totl Distrbuion Plant Acum Depreciation B17 (2,003,311,485)(1,891,870,183)(111,441,302)(111,441,302)
2346
2347 Summar of Distrbutn Plant Depr by Factr
234 S (2.003,311.485)(1.891.870.183)(111.441.302)(111.441.302)
2349
2350 Total Distrn Depretin by Facor 817 (2.003,311.48)(1.91.870.183)(11.441.302)(111.441.302)
REVISED PROTOCOL Page 2.38
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2351 108GP General Plant Accumulated Depr
2352 G-SITUS S (151,989,352)(141,794,438)(10,194,914)(10,194,914)
2353 PT SG (6,272,465)(5,926,947)(345,519)(345,519)
2354 PT SG (11,172,030)(10,556,619)(615,411)(615,411)
2355 G-SG SG (46,253,779)(43,705,891 )(2,547.888)(2,547,888)
2356 CUST CN (6,625,150)(6,367,792)(257,358)(257,358)
2357 PTD SO (72,527,529)(68,616,614)(3,910,915)(3.910,915)
2358 P SE (339.900)(318,291)(21,609)(21.609)
2359 G-SG SSGCT (33,094)(31,288)(1,806)(1,806)
2360 G-SG SSGCH (2,331,547)(2,204,523)(127.023)(127,023)
2361 817 (297,544,84)(279,522,403)(18,022,444)(18.022,444)
2362
2363
2364 108MP Mining Plant Accumulated Depr.
2365 P S
2366 P SE (170,270.750)(159,445.750)(10.825,000)(41.661 )(10,866,661 )
2367 817 (170.270,750)(159,445,750)(10,825,000)(41,661)(10,866,661)
2368 108MP Less Centralia Situs Depreciation
2369 P S
2370 817 (170,270,750)(159,445,750)(10,825,000)(41,661)(10,866,661 )
2371
2372 1081390 Accum Depr - Capital Lease
2373 PTD SO 817
2374
2375
2376 Remove Capital Leases
2377 817
2378
2379 1081399 Accum Depr - Capital Lease
2380 p S
2381 P SE 817
2382
2383
2384 Remove Capital Leases
2385 817
2386
2387
2388 Total General Plant Accum Depreciation B17 (467,815,596)(438,968,153)(28,847,44)(41,661)(28,889,104)
2389.
2390
2391
2392 Summary of General Depreciation by Factor
2393 S (151.989,352)(141,794.438)(10,194,914)(10,194,914)
2394 DGP
2395 DGU
2396 SE (170,610.651) .(159,764,042)(10,84,609)(41,661)(10.888.270)
2397 SO (72,527.529)(68,616.614)(3,910,915)(3,910,915)
2398 CN (6,625,150)(6,367,792)(257,358)(257,358)
2399 SG (63,698,274)(60,189,456)(3,508,818)(3,508,818)
2400 DEU
2401 SSGCT (33,094)(31,288)(1,806)(1,806)
2402 SSGCH (2,331,547)(2,204,523)(127,023)(127,023)
2403 Remove Capital Leases
2404 Total General Depreciation by Factor (467,815,596)(438,968,153)(28,847,443)(41.661)(28,889,104)
2405
2406
2407 Totl Accum Depreciation. Plant In Service 617 (6,626,518,392)(6,257,435,755)(369,082,637)(2,54,082)(371,626,719)
2408 111SP Accum Prov for Amort-Steam
2409 p SG
2410 P SSGCT
2411 818
2412
2413
2414 111GP Accum Prov for Amort-General
2415 G-SITUS S (15.417.186)(15,417.186)
2416 CUST CN (2.453.306)(2,358,005)(95,300)(95.300)
2417 l-SG SG
2418 PTD SO (9,907.217)(9,372.989)(534.229)(534,229)
2419 P SE -
2420 618 (27.777,708)(27.148,179)(629,529)(629,529)
2421
REVISED PROTOCOL Page 2.39
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DE SCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2422
2423 111HP Accum Prov for Amort-Hydro
2424 P SG
2425 P SG
2426 P SG (13.027)(12,310)(718)(718)
2427 P SG (390.637)(369,119)(21.518)(21.518)
2428 B18 (403,664)(381,429)(22,236)(22,236)
2429
2430
2431 1111P Accum Prov for Amort-Intangible Plant
2432 I-SITUS S (866.992)(130,826)(736,166)(736,166)
2433 P SG
2434 P SG (332.638)(314.315)(18,323)(18,323)
2435 P SE (1.011.087)(946.807)(64.280)(64,280)
2436 1-5G SG (42.153.361)(39,831.344)(2,322.017)(25.402)(2,347,419)
2437 I-SG SG (11,454.352)(10,823.389)(630.963)(630.963)
2438 I-SG SG (3.111,807)(2.940.393)(171,414)(171.414)
2439 CUST CN (89.511.348)(86.034,220)(3.477,128)(3,477.128)
244 P SSGCT
2441 P SSGCH (67,877)(64,179)(3,698)(3.698)
2442 PTD SO (250.449.855)(236.944,804)(13,505,051 )(13,505,051)
2443 B18 (398.959.316)(378.030,277)(20.929.040)(25,402)(20.954,442)
2444 1111P Less Non-Utilty Planí
2445 NUTIL OTH
2446 (398.959,316)(378.030.277)(20.929.040)(25.402)(20.954.442)
2447
2448 111390 Accum Amtr - Capital Lease
2449 G.SITUS S (5,302,423)(5.302,423)
2450 P SG (1.390,857)(1,314.242)(76.615)(76.615)
2451 PTD SO 1.860.994 1,760.643 100.351 100.351
2452 (4,832.287)(4,856,022)23.735 23.735
2453
2454 Remove Capita Leae Amtr 4.832.287 4.856,022 (23,735)(23,735)
2455
2456 Total Accum Provision for Amortzation B18 (42 .140,689)(405,559,885)(21,580,804)(25,402)(21.606,207)
2457
2458
2459
2460
2461 Summary of Amortization by Factor
2462 S (21,586.600)(20,850.43)(736.166)(736.166)
2463 DGP
2464 DGU
2465 SE (1.011.087)(946.807)(64.280)(64,280)
2466 SO (258,496,078)(244,557,149)(13.938,929)(13.938,929)
2467 CN (91.964.653)(88,392,225)(3.572.428)(3.572,428)
246 SSGCT
2469 SSGCH (67.877)(64.179)(3.698)(3.698)
2470 SG (58.846.679)(55.605.111 )(3.241.568)(25.402)(3.266.970)
2471 Less Capital Lease 4.832.287 4.856.022 (23,735)(23.735)
2472 Total Provision For Amortization by Factor (427,140.689)(405.559.85)(21.58p,804)(25,402)(21,606.207)
Rocky Mountain Power
RESULTS OF OPERATIONS
Page 9.1
USER SPECIFIC INFORMATION
STATE:
PERIOD:
IDAHO
DECEMBER 2009
FILE:
PREPARED BY:
DATE:
TIME:
JAM Dec 200910 GRC_Rebuttal
Revenue Requirement Departent
11/10/2010
10:18:53 AM
TYPE OF RATE BASE:
ALLOCATION METHOD:
Year-End
ROLLED-IN
FERC JURISDICTION:Separate Jurisdiction
80R 12 CP:12 Coincidental Peaks
DEMAND %
ENERGY %
75% Demand
25% Energy
TAX INFORMATION
TAX RATE ASSUMPTIONS:
FEDERAL RATE
STATE EFFECTIVE RATE
TAX GROSS UP FACTOR
FEDERAUSTATE COMBINED RATE
TAX RATE
35.00%
4.54%
1.615
37.951%
CAPITAL STRUCTURE INFORMATION
CAPITAL
STRUCTURE
EMBEDDED
COST
WEIGHTED
COST
DEBT
PREFERRED
COMMON
47.60%
0.30%
52.10%
100.00%
5.88%
5.42%
10.60%
2.799%
0.016%
5.523%
8.338%
OTHER INFORMATION
Th Company's current estimated cost of equity is 10.6%. The capital structure is calculated using the five quarter average from
12/31/2009 to 1213112010.
ROLLED.IN Page 9.2
Year.End
RESULTS OF OPERATIONS SUMMARY
UNADJUSTED RESULTS IDAHO
Description of Account Summary:Ref TOTAL OTHER IDAHO ADJUSTMENTS ADJTOTAL
1 Operating Revenues
2 General Business Revenues 2.3 3,484,413.565 3,297,654,176 186,759,389 15,973.773 202,733,162
3 Interdepartmental 2.3 0 0 0 0 0
4 Special Sales 2.3 643,321,157 608.334,858 34,986,299 12,195,096 47,181,395
5 Other Operating Revenues 2.4 226,031,658 211,768,550 14,263,108 (489.545)13,773,563
6 Total Operating Revenues 2.4 4,353,766,380 4.117,757,584 236,008,796 27,679,324 263,688,120
7
8 OperangExpenses:
9 Steam Production 2.5 898,300,862 843.521,228 54,779,635 5.860,288 60,639,923
10 Nuclear Production 2.6 0 0 0 0 0
11 Hydro Production 2.7 37,924,259 35,835,202 2,089.057 44.873 2.133,930
12 Other Power Supply 2.9 1,023,694.683 960.746.228 62,948,455 14.696,441 77,644,895
13 Transmission 2.10 172,874.522 163.342,030 9,532,492 1,214.384 10,746.876
14 Distrbution 2.12 215.468,741 204.320,401 11,148,340 286,225 11,434.564
15 Customer Accounting 2.12 93,785,007 89.279,506 4.505,501 138,335 4.643,836
16 Customer Service & Infor 2.13 71,462.744 64.626,109 6.836.635 (4.989,177)1,847.458
17 Sales 2.13 0 0 0 0 0
18 Administrative & General 2.14 162.619,511 153.143,351 9,476.160 2.017,070 11,493.230
19
20 Total 0 & M Expenses 2.14 2,676,130,329 2,514,814,055 161,316.274 19,268,439 180,584,713
21
22 Depreciation 2.16 48,027,603 439,648,393 24,379,210 3,058,619 27,437,829
23 Amortization 2.17 43,698,570 41,446,814 2,251,756 (150,962)2,100,794
24 Taxes Other Than Income 2.17 123,877,487 118,554,217 5,323,269 414,144 5,737,413
25 Income Taxes. Federal 2.20 (169.394,084)(156,583,204)(12,810.880)(16,490.301)(29,301,181)
26 Income Taxes. State 2.20 (21,767,423)(20,087,707)(1,679.716)(1,795,311)(3,475,027)
27 Income Taxes. Def Net 2.19 482,616,183 458,790,118 23,826,065 16.785,518 40.611,583
28 Investment Tax Credit Adj.2.17 (1,874.204)(1,672.710)(201,494)0 (201,494)
29 Mise Revenue & Expense 2.4 (5,975,707)(5,678,965)(296.742)(284,193)(580,935)
30
31 Total Operating Expenses 2.20 3,591.338.753 3.389.231,011 202.107,742 20,805,953 222,913.695
32
33 Operating Revenue for Return 762,427.627 728.526,573 33,901.054 6,873,371 40.774,425
34
35 Rate Base:
36 Elecric Plant in Service 2.30 19.556.037,605 18.501.147.212 1.054,890,394 112.270,443 1,167,160,837
37 Plant Held for Future Use 2.31 13,674,54 13.104,516 570,032 (570,032)0
38 Mise Deferrd Debits 2.33 140,117,584 136,496,23 3.620.962 553,302 4.174,263
39 Elec Plant Acq Adj 2.31 60,866,907 57,514,055 3.352.852 0 3,352,852
40 Nuclear Fuel 2.31 0 0 0 0 0
41 Prepayments 2.32 46,150,453 43,579,532 2,570,921 0 2,570.921
42 Fuel Stock 2.32 167,792.599 157,125,148 10.667,451 1,504,805 12,172,256
43 Material & Supplies 2.32 177,874,022 167,911,805 9,962,217 0 9,962,217
44 Working Capital 2.33 55.832,776 52,903.622 2,929.154 (25,961)2,903,193
45 Weatherizatin Loans 2.31 37.358,188 33,854,54 3,503,640 0 3,503,640
46 Miscellaneous Rate Base 2.34 1,809,172 1,685.894 123,279 0 123.279
47
48 Total Electric Plant 20,257,513.854 19,165,322,953 1,092,190,901 113,732,557 1,205,923,459
49
50 Rate Base Deductons:
51 Accum Prov For Depr 2.38 (6,626,518,392)(6,257,327,216)(369,191,176)(2.544,082)(371,735,257)
52 Accum Prov For Amort 2.39 (427,140,689)(405,554,960)(21,585,729)(25,402)(21,611.131 )
53 Accum Def Income Taxes 2.35 (2,332.318,663)(2,191,772.384)(140,546,299)(15,147,668)(155.693,967)
54 Unamortd ITC 2.35 (7,294,22)(7,250,054)(44,168)(166,992)(211.161 )
55 Customer Adv for Const 2.34 (20,944,658)(20,258,001 )(686,658)(261,039)(947,697)
56 Customer Service Deposits 2.34 0 0 0 0 0
57 Mise. Rate Base Deuctions 2.34 (57,365,19)(54,678,237)(2,687,183)(2,204,752)(4,891,935)
58
59 Total Rate Base Deductions (9,471,582,043)(8,936,840,831)(534.741.212)(20,349,935)(555,091,147)
60
61 Total Rate Base 10,785.931,811 10,228.482.122 557,449.689 93,382,623 650,832.312
62
63 Retum on Rate Ba 7.069%6.081%6.265%
84
65 Retum on Equi 8.164%6.269%6.622%
66 Net Power Cost 1,042,847,44 67,217,503 69,190,569
67 100 Basis Points in Equl:
68 Rev Requirement Impact 90,565,045 4,680,676 5,64,772
69 Ra Bae Decrese (740,405,227)(43,988.376)(49,968,364)
ROLLED~IN Page 9.3
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
70 Sales to Ultmate Customers
71 440 Residential Sales
72 0 S 1.346.519.773 1.287.272.744 59.247.029 386,357 59,633,386
73
74 81 1.346,519,773 1.287,272.744 59.247.029 386,357 59,633,386
75
76 442 Commercial & Industrial Sales
77 0 S 2,097,948.247 1.970.908.587 127.039,660 15,459.595 142,499.255
78 P SE
79 PT SG
80
81
82 81 2,097.948.247 1.970.908.587 127,039.660 15.459.595 142,499.255
83
84 444 Public Street & Highway Lighting
85 0 S 20.913,398 20,440.698 472,700 127.821 600.521
86 0 SO
87 81 20.913.398 20,440.698 472,700 127.821 600.521
88
89 445 Other Sales to Public AuthOnty
90 0 S 19.032,148 19.032.148
91
92 81 19.032.148 19,032.148
93
94 448 Interdepartmental
95 DPW S
96 GP SO
97 81
98
99 Total Sales to Ultimate Customers B1 3,484,413,565 3,297.654,176 186,759,389 15,973,773 202.733,162
100
101
102
103 447 Sales for Resale-Non NPC
104 WSF S 8,352,641 8,352,641
105 8,352.641 8.352.641
106
107 447NPC Sales for Resale.NPC
108 WSF SG 633.900.033 598.981.663 34.918,370 12.263.025 47,181.395
109 WSF SE 1,068,483 1,000.554 67.929 (67,929)
110 WSF SG
111 634.968.516 599.982.217 34.986.299 12,195,096 47.181.395
112
113 Total Sales for Resale 81 643.321.157 608.334.858 34.986.29 12.195.096 47,181.395
114
115 449 Provision for Rate Refund
116 WSF S
117 WSF SG
118
119
120 81
121
122 Totl Sales frm Electricit B1 4,127,734,722 3,905,989,034 221,745,688 28,168,869 249,914,557
123 450 Forfeited Discunts & Interest
124 CUST S 7.318,368 6,907,026 411.342 411,342
125 CUST SO
126 B1 7,318,368 6.907.026 411,342 411.342
127
128 451 Mise Electc Revenue
129 CUST S 6.902,761 6,732,681 170.080 170,080
130 GP SG
131 GP SO 6.131 5.801 331 331
132 B1 6.908,893 6.738.482 170,411 170,411
133
134 453 Water Sales
135 P SG 12.155 11.485 670 670
136 B1 12.155 11,485 670 670
137
138 45 Rent of Elect Propert
139 DPW S 10,421,181 10,119.677 301.504 301,504
140 T SG 5.30.571 5.012.368 292.202 292,202
141 T SG 4.88 4.617 269 269
142 GP SO 3,428,29 3.243.365 184.929 184,929
143 B1 19.158,931 18.380,027 778.904 778.904
144
145
ROLLED-IN Page 9.4
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
146
147 456 Other Electric Revenue
148 OMSC S 50,609,068 45,598,459 5,010.609 (5.010.486)123
149 CUST CN
150 OTHSE SE 8.005,386 7.496.442 508,94 508.944
151 OTHSO SO 173,123 163,784 9.339 9.339
152 OTHSGR SG 133.845.735 126.472.845 7.372,890 4,520.941 11.893.830
153
154
155 B1 192.633,312 179.731.530 12.901.781 (489,545)12,412.236
156
157 Total Other Electric Revenues B1 226,031.658 211,768,550 14,263,108 (489,545)13,773,563
158
159 Total Electric Operating Revenues B1 4,353,766,380 4,117,757,584 236,008,796 27,679,324 263,688,120
160
161 Summary of Revenues by Factor
162 S 3.568.017,584 3.375,364,659 192,652,925 10.963.287 203.616.212
163 CN
164 SE 9,073,869 8.496,996 576,873 (67.929)508.944
165 SO 3.607.548 3,412.950 194.598 194.598
166 SG 773.067,379 730,482.978 42.584,400 16,783,96 59.368.366
167 OGP
168
169 Total Electric Operating Revenues 4.353.766.380 4.117.757.584 236.08.796 27.679.324 263.688.120
170 Miscellaneous Revenues
171 41160 Gain on Sale of Utilty Plant - CR
172 OPW S
173 T SG
174 G SO
175 T SG
176 P SG
177 B1
178
179 41170 Loss on Sale of Utilty Plant
180 OPW S
181 T SG
182 B1
183
184 4118 Gain from Emission Allowances
185 P S
186 P SE (3.790,891 )(3.549.884)(241.007)(284.193)(525.200)
187 61 (3.790,891)(3.549.884)(241.007)(284.193)(525.200)
188
189 41181 Gain from Dispositon of N9X Credits
190 P SE
191 81
192
193 4194 Impact Housing Interest Income
194 P SG
195 B1
196
197 421 (Gain) I Loss on Sale of Utilty Plant
198 OPW S (1.173.272)(1.173.272)
199 T SG (145.556)(137.538)(8,018)(8,018)
200 T SG (68.192)(64,436)(3.756)(3,756)
201 PTO CN
202 PTO SO 12,862 12.168 694 694
203 P SG (810,657)(766.002)(44,655)(44.655)
204 B1 (2.184,816)(2.129,080)(55.736)(55,736)
205
206 Total Miscellaneous Revenues (5,975.707)(5,678,965)(296,742)(284,193)(580,935)
207 Miscellaneous Expenss
208 4311 Interest on Custmer Deposits
209 CUST S
210 B1
211 Total Miscellaneous Expeses
212
213 Net Mise Revenue and Expense 81 (5,975,707)(5,678,965)(296,742)(284,193)(580,935)
214
ROLLED-IN Page 9.5
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
215 500 Operation Supeivision & Engineenng
216 P SNPPS 20,160.039 19,049.523 1,110.515 37,227 1,147,743
217 P SNPPS 1.216,352 1.149,349 67.003 67.003
218 62 21.376,391 20,198,873 1,177,518 37,227 1,214,745
219
220 501 Fuel Related-Non NPC
221 P SE 11,157,930 10,448,562 709,368 1.067 710,434
222 P SE
223 P SE
224 P SE
225 P SE 3,213,384 3,009,093 204.292 204,292
226 62 14.371,314 13,457,654 913,659 1.067 914.726
227
228 501NPC Fuel Related-NPC
229 P SE 552,903,370 517,752,418 35,150,952 5,77,942 40.628.893
230 P SE
231 P SE
232 P SE
233 P SE 52,991.371 49,622,433 3.368,938 3,368.938
234 62 605,894,741 567.374,851 38,519,889 5.477.942 43,997,831
235
236 Total Fuel Related 620,266,055 580,832.506 39,433,549 5,479,008 44,912,557
237
238 502 Steam Expenses
239 P SNPPS 30,407.397 28,732.406 1,674,991 41,453 1,716.444
240 P SNPPS 5,101.692 4,820,666 281,027 281,027
241 62 35.509.090 33,553,072 1.956,017 41,453 1.997,470
242
243 503 Steam From Other Sour's-Non-NPC
244 P SE 147 147
245 62 147 147
246
247 503NPC Steam From Other Sources-NPC
248 P SE 3,597.576 3.368,859 228.717 (14,218)214,498
249 62 3,597.576 3,368,859 228,717 (14.218)214,498
250
251 505 Electnc Expenses
252 P SNPPS 2.754.507 2,602.775 151,732 3,675 155,407
253 P SNPPS 1,150,021 1.086,672 63.349 63;349
254 62 3,904.528 3,689,447 215,081 3,675 218,756
255
256 506 Misc. Steam Expense
257 P SNPPS 42,056.734 39.740,040 2.316,694 91.485 2.408.179
258 P SE
259 P SNPPS 1,502,518 1,419,752 82.766 82,766
260 62 43.559,253 41.159,792 2,399,461 91,485 2,490,945
261
262 507 Rents
263 P SNPPS 448.653 423,939 24,714 24.714
264 P SNPPS 1,762 1,665 97 97
265 62 45,415 425,604 24,811 24.811
266
267 510 Maint Supeivision & Engineering
268 P SNPPS 4,057,736 3,834.216 223.520 33,811 257,331
269 P SNPPS 1,912.378 1,807,035 105.343 105,343
270 62 5.970.114 5.641,250 328,864 33.811 362,674
271
272
273
274 511 Maintenanc of Structures
275 P SNPPS 21.886.763 20,681,131 1,205,632 14,386 1,220.018
276 P SNPPS 938,302 c886.616 51.686 51,686
277 62 22.825.065 21,567,747 1,257.318 14.386 1.271,704
278
279 512 Maintenance of 60iler Plant
280 P SNPPS 91,029,755 86,015,382 5.014.372 141,429 5.155.801
281 P SNPPS 3.403.827 3,216,327 187,500 187.500
282 62 94,433.581 89,231,709 5,201.872 141.429 5.343,300
283
284 513 Maintenanc of Ele Plant
285 P SNPPS 33.316.896 31,481,635 1.835.260 25.634 1.860,894
288 P SNPPS 410.626 388.007 22.619 22,619
287 62 33.727.522 31.869.642 1.857,880 25.634 1.883,514
288
289 514 Maintenan of Misc. Steam Plant
290 P SNPPS 9.660.457 9,128,311 532,146 6,253 538,400
291 P SNPPS 3.020.817 2.854,415 166.402 166,402
292 62 12.681.274 11,982.726 698,548 6,253 704,801
29329 Tot Steam Powr Generaon B2 89,3,862 84,521,228 54,779,635 5,860,2 60,639,923
ROLLED-IN Page 9.6
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
295 517 Operation Super & Engineering
296 P SNPPN
297 62
298
299 518 Nuclear Fuel Expense
300 P SE
301
302 62
303
304 519 Coolants and Water
305 P SNPPN
306 62
307
308 520 Steam Expenses
309 P SNPPN
310 62
311
312
313
314 523 E.lectric Expenses
315 P SNPPN
316 62
317
318 524 Misc. Nuclear Expenses
319 P SNPPN
320 62
321
322 528 Maintenance Super & Engineering
323 P SNPPN
324 62
325
326 529 Maintenance of Structures
327 P SNPPN
328 62
329
330 530 Maintenance of Reactor Plant
331 P SNPPN
332 62
333
334 531 Maintenance of Electric Plant
335 P SNPPN
336 82
337
338 532 Maintenance of Mise Nuclear
339 P SNPPN
340 82
341
342 Total Nuclear Power Generation B2
343
344 535 Operation Super & Engineering
345 P DGP
346 P SNPPH 8,095,68 7,649,732 445,951 20,742 466,692
347 P SNPPH 1,289.537 1,218,502 71,034 71,034
348
349 82 9.385,219 8,868,235 516.985 20.742 537,726
350
351 536 Water For Powr
352 P DGP
353 P SNPPH 285.794 270.051 15,743 188 15,931
354 P SNPPH 4.415 4,172 243 243
355
356 62 290.209 274,223 15.986 188 16.174
357
ROLLED-IN Page 9.7
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DE SCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
358 537 Hydraulic Expenses
359 P DGP
360 P SNPPH 3.168.766 2.994,214 174.551 1,44 175,996
361 P SNPPH 349.84 330.573 19,271 19.271
362
363 82 3.518.610 3,324.787 193,823 1,444 195.267
364
365 538 Electric Expenses
366 P DGP
367 P SNPPH
368 P SNPPH
369
370 82
371
372 539 Misc. Hydro Expenses
373 P DGP
374 P SNPPH 11.894.606 11,239.392 655,214 17,690 672.904
375 P SNPPH 5.705.129 5,390.862 314,267 314.267
376
377
378 82 17.599,735 16.630.254 969,481 17.690 987,171
379
380 540 Rents (Hydro Generation)
381 P DGP
382 P SNPPH 180.404 170.466 9,938 (33)9.904
383 P SNPPH 3.040 2,873 167 167
384
385 82 183,44 173.339 10.105 (33)10.072
386
387 541 Maint Supervision & Engineering
388 P DGP
389 P SNPPH 84.358 79.711 4.647 2 4,649
390 P SNPPH
391
392 82 84,358 79.711 4.647 2 4.649
393
394 542 Maintenance of Structures
395 P DGP
396 P SNPPH 1.092.399 1.032.224 60.175 802 60.977
397 P SNPPH 114.713 108,394 6,319 6.319
398
399 82 1,207.112 1,140,619 66,494 802 67.296
400
401
402
403
404 543 Maintenance of Dams & Waterwys
405 P DGP
406 P SNPPH 1,189.774 1.124.235 65.539 912 66,450
407 P SNPPH 410.765 388.138 22.627 22.627
408
409 82 1.600.539 1,512,374 88,166 912 89.077
410
411 544 Maintenance of Electric Plant
412 P DGP
413 P SNPPH 1.188,647 1.123.171 65,477 1.671 67,148
414 P SNPPH 327,068 309.052 18,017 18.017
415
416 82 1.515,716 1,432.223 83,493 1,671 85.164
417
418 545 Maintenance of Misc. Hydro Plant
419 P DGP
420 P SNPPH 1.925,303 1.819.248 106.055 1,455 107.510
421 P SNPPH 614.013 580,190 33.823 33.823
422
423 82 2.539.316 2,399,438 139.878 1.455 141,333
424
425 Totl Hydraulic Power Generation B2 37,924,259 35,835,202 2,089,057 44,873 2,133,930
ROLLED.IN Page 9.8
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DE SCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
426
427 546 Operation Super & Engineenng
428 P SNPPO 316.964 299.504 17,460 63 17.523
429 P SNPPO
430 82 316.964 299.504 17.460 63 17.523
431
432 547 Fuel-Non-NPC
433 P SE
434 P SE
435 82
436
437 547NPC Fuel-NPC
438 P SE 426.253.895 399.154.711 27.099.184 1.326.130 28,25.314
439 P SE 35.489,120 33.232.892 2.256,229 2.256.229
44 62 461,743,015 432.387.603 29.355,412 1.326.130 30,681,542
441
442 548 Generation Expense
443 P SNPPO 14.113.019 13.335,604 777,415 12,516 789.931
444 P SNPPO 1.626,465 1.536.872 89.594 89.594
445 82 15.739.485 14.872,475 867,009 12,516 879.525
44
447 549 Miscellaneous Other
448 P SNPPO 18.635.853 17.609.298 1.026,556 330,179 1,356.734
449 P SNPPO
45 62 18.635.853 17,609,298 1.026.556 330,179 1.356.734
451
452
453
454
455 550 Rents
456 P SNPPO 1.861.263 1.758.736 102.528 102.528
457 P SNPPO
458 62 1,861.263 1.758,736 102.528 102.528
459
460 551 Maint Supervision & Engineering
461 P SNPPO
462 62
463
464 552 Maintenance of Structures
465 P SNPPO 1.350.705 1.276.301 74.404 613 75.016
466 P SNPPO 193.326 182.677 10.649 10.649
467 62 1.54.031 1,458.978 85.053 613 85.666
468
469 553 Maint of Generation & Electrc Plant
470 P SNPPO 12.141.793 11,472,963 668.830 (218,282)450.548
471 P SNPPO 2.845.46 2.688,327 156,719 156.719
472 82 14.986,84 14.161.29 825.550 (218.282)607.267
473
474 554 Maintenance of Misc. Other
475 P SNPPO 1.200,375 1.134.253 66.123 283 66.405
476 P SNPPO 121.530 114.836 6.694 6.694
477 82 1.321,906 1.249.089 72.817 283 73.100
478
479 Total Other Power Generation B2 516,149,358 483,796,973 32,352,385 1,451,500 33,803,885
480
481
482 555 Purchased Power-Non NPC
483 DMSC S (33.207.768)(33,362,478)154.710 (154,710)
484 (33.207.768)(33.362,478)154.710 (154.710)
48548 555NPC Purchase Power.NPC
487 P SG 409.727.945 387.158.090 22.569.855 6.802,349 29,372.204
48 P SE 79.691,472 74.625.070 5,066.403 (584,201)4.482,201
489 Seasonal Co P SG
490 DGP
491 489,419,417 461.783.159 27,636.258 6.218.147 33.854.405
492
493 Total Purcase Power 62 456.211,649 428,420.681 27.790.968 6.063.437 33.854.405
494
495 556 System Contl & Load Dispatch
496 P SG 1.514.461 1,431.037 83,424 1.524 84.948
497
498 B2 1,514,461 1,431,037 83,424 1.524 84.948
499
500
ROLLED-IN Page 9.9
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESeRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
501
502 557 Other Expenses
503 P S (183,792)(150,819)(32,973)7,585,721 7,552,748
504 P SG 48,880,583 46,187,997 2,692.586 (405.742)2.286.844
505 P SGCT 1,122,425 1,060,360 62,065 62,065
506 P SE
507 P SG
508 P TROJP
509
510 62 49,819,215 47,097,537 2,721,678 7,179,979 9,901,657
511
512 Embedded Cost Diferentials
513 Company Owned Hyd P DGP
514 Company Owned Hyd P SG
515 Mid-G Contract P MC
516 Mid-G Contract P SG
.517 Existing OF Contracts P S
518 Existing OF Contracts P SG
519
520
521
522 Total Other Power Supply B2 507,54,325 476,949,255 30,596.070 13,244,941 43,841,011
523
524 Total Production Expense B2 1,959,919,804 1,84,102,658 119,817,146 20,601,603 140,418,749
525
526
527 Summary of Producton Expense by Factor
528 S (33,391,560)(33,513,297)121,737 7,431,011 7.552,748
529 SG 460,122,988 434,777,123 25,345,865 6,398,131 31,743,996
530 SE 1.165,298,118 1,091,214.038 74,084,080 6,206,865 80,290.945
531 . SNPPH 37,924,259 35,835,202 2,089,057 44,873 2,133,930
532 TROJP
533 SGCT 1,122,425 1,060,360 62,065 62,065
534 DGP
535 DEU
536 DEP
537 SNPPS 274,437,232 259,319,863 15,117,369 395,352 15,512,721
538 SNPPO 54,406,342 51,409,370 2,996,972 125,370 3,122,343
539 DGU
540 MC
541 SSGCT
542 SSECT
543 SSGC
544 SSGCH
545 SSECH54Total Production Expense by Factor 62 1,959,919,804 1,840,102,658 119,817,146 20,601,603 140,418,749
547 560 Operation Supervision & Engineering54TSNPT 6,088,583 5,753,193 335,389 10,916 346,305
549
550 62 6.088,583 5,753,193 335.389 10,916 346.305
551
552 561 Load Dispatching
553 T SNPT 9,323,709 8.810,112 513.596 18.577 532.174
554
555 62 9.323,709 8,810,112 513.596 18.577 532.174
556 562 Station Expense
557 T SNPT 1.506,478 1,423,494 82.984 2.259 85,243
558
559 62 1,506,478 1,423,94 82,984 2,259 85.243
560
561 563 Overhead Line Expense
562 T SNPT 245,152 231,646 13,504 206 13,710
56356 62 245,152 231.646 13,504 20 13,710
56
566 564 Underground Line Expense
567 T SNPT
568
569 62
570
ROLLED-IN Page 9.10
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAH ADJUSTMENT ADJTOTAL
571 565 Transmission of Electricit by Others
572 T SG
573 T SE
574
575
576 565NPC Transmission of Electricity by Others-NPC
577 T SG 116.018,414 109.627,542 6,390.872 1,066,721 7,457,592
578 T SE 1,142,797 1,070,143 72,654 93,442 166.095
579 117,161,210 110,697,685 6,463,525 1,160.162 7,623,688
580
581 Total T ransm ission of Electricity by Othe~82 117,161,210 110.697,685 6,463,525 1,160.162 7,623,688
582
583 566 Misc. Transmission Exense
584 T SNPT 2,393,112 2,261,287 131,825 (4,285)127,540
585
586 82 2,393,112 2,261,287 131,825 (4,285)127,540
587
588 567 Rents - Transmission
589 T SNPT 1,656,975 1,565,700 91,274 509 91.784
590
591 82 1,656,975 1,565,700 91.274 509 91,784
592
593 568 Maint Supervision & Engineering
594 T SNPT 35,453 33,500 1.953 39 1,992
595
596 82 35,453 33,500 1,953 39 1,992
597
598 569 Maintenance of Structures
599 T SNPT 4,060,56 3,836,884 223,676 5,35 229,110
600
601 82 4,060,560 3,836,884 223,676 5,435 229,110
602
603 570 Maintenance of Station Equipment
604 T SNPT 10,549,624 9,968,498 581,126 16.773 597,899
605
606 82 10,549.624 9.968,498 581,126 16,773 597,899
607
608 571 Maintenance of Overhead Lines
609 T SNPT 19,620,066 18,539,295 1,080,771 3,679 1,084,449
610
611 82 19,620,066 18,539.295 1,080,771 3.679 1,084.449
612
613 572 Maintenance of Underground Lines
614 T SNPT 51,599 48,757 2.842 84 2,926
615
616 82 51.599 48,757 2,842 84 2,926
617
618 573 Maint of Misc. Transmission Plant
619 T SNPT 182,001 171,976 10,026 30 10,056
620
621 82 182,001 171,976 10,026 30 10.056
622
623 Total Transmission Expense B2 172,874,522 163.342,030 9,532,492 1,214,384 10,746.876
624
625 Summary of Transmission Expense by Factor
626 SE 1,142,797 1,070.143 72,654 93,42 166,095
627 SG 116,018,414 109,627,542 6,390,872 1,066,721 7,457,592
628 SNPT 55,713,312 52,644,345 3,068,967 54,222 3,123,188
629 Total Transmission Expense by Factor 172,874,522 163,342.030 9.532,492 1,214,384 10,746,876
630 580 Operan Supervision & Engineering
631 DPW S 1,012,44 930,166 82,277 82,277
632 DPW SNPD 18,641,946 17,781,836 860,111 34,479 894,590
633 82 19,654,389 18,712,001 942.388 34,479 976,867
634
635 581 Load Dispatching
636 DPW S
637 DPW SNPD 13,439,746 12.819,657 620,089 25,714 645,803
638 82 13,439,746 12,819,657 620,089 25,714 645.803
639
640 582 Statin Expns
641 DPW S 3,849,839 3,641,292 208,547 4,008 212,555
642 DPW SNPD 29,84 28,471 1,317 46 1,423
643 B2 3,879,687 3,669.763 209,924 4,053 213,977
64
ROLLED-IN Page 9.11
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
645 583 Overhead Line Expenses
646 DPW S 5.777.056 5,475,120 301,936 11.118 313,054
647 DPW SNPD 17.767 16,98 820 29 849
648 82 5.794.824 5,492.068 302.756 11.147 313,903
649
650 584 Underground Line Expense
651 DPW S 305 305
652 DPW SNPD
653 B2 305 305
654
655 585 Street Lighting & Signal Systems
656 DPW S
657 DPW SNPD 207.152 197,594 9,558 402 9,960
658 82 207.152 197.594 9,558 402 9.960
659
660 586 Meter Expenses
661 DPW S 5,630.733 5,374.972 255,761 9,193 264,954
662 DPW SNPD 1,082.827 1,032,867 49.960 1,765 51,725
663 82 6.713.560 6,407,839 305,721 10,958 316.679
664
665 587 Customer Installation Expenses
666 DPW S 12,458,762 12,009.848 44,917 16,305 465,222
667 DPW SNPD 496 473 23 1 24
668 82 12.459,259 12.010,319 448,940 16,306 465,246
669
670 588 Misc. Distrbution Expenses
671 DPW S 1.903,892 1,827.783 76,109 (2.139)73,970
672 DPW SNPD 5,537,508 5.282,016 255,492 (46)255,446
673 82 7,441,400 7,109.799 331.601 (2.186)329,416
674
675 589 Rents
676 DPW S 3,082.013 3,056,279 25,733 33 25,767
677 DPW SNPD 114,242 108,971 5,271 0 5.271
678 82 3,196.255 3,165.250 31,004 33 31,038
679
680 590 Maint Supervision & Engineering
681 DPW S 1,168.290 1.079,917 88.373 3,126 91,498
682 DPW SNPD 6.367,680 6.073,885 293,795 10,425 304.219
683 82 7,535,970 7.153,802 382.168 13,550 395.718
684
685 591 Maintenance of Structures
686 DPW S 1,855.991 1,709,849 146.142 146,12
687 DPW SNPD 159.999 152,617 7,382 7,382
688 82 2,015,990 1,862,46 153.524 153,524
689
690 592 Maintenance of Station Equipment
691 DPW S 10,926,178 10,135.064 791,114 25,517 816.631
692 DPW SNPD 1,874,179 1.787,708 86,472 3.387 89.858
693 82 12,800.357 11,922,771 87758 28.904 906,490
694 593 Maintenance of Overhead Lines
695 DPW S 82.112,317 77,011,054 5.101,264 100.942 5.202.206
696 DPW SNPD 1.224,337 1,167,848 56.489 951 57,440
697 82 83,336.655 78.178.902 5.157,753 101,893 5,259,646
698
699 594 Maintenance of Underground Lines
700 DPW S 22,479,205 21.746.414 732,791 18.984 751,774
701 DPW SNPD 7,391 7,050 341 11 352
702 82 22.486,595 21.753,464 733,132 18,995 752.126
703
704 595 Maintenance of Line Transformers
705 DPW S 24.717 24.717
706 DPW SNPD 1,081,164 1,031,280 49.88 1,698 51,581
707 62 1,105.880 1.055,997 49.883 1,698 51.581
708
709 596 Malnt of Street Lighting & Signal Sys.
710 DPW S 4.217,687 4,084.975 132,712 4.670 137.382
711 DPW SNPD
712 B2 4,217.687 4,084.975 132,712 4,670 137.382
713
ROLLED-IN Page 9.12
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
714 597 Maintenance of Meters
715 DPW S 4.536.131 4,239,464 296.667 10.873 307,541
716 DPW SNPD 1.100,892 1,050,098 50,793 1,662 52,455
717 B2 5.637,023 5,289,562 347,461 12.535 359,996
718
719 598 Maint of Misc. Distrbution Plant
720 DPW S 2.967,838 2.882.374 85,465 128 85.592
721 DPW SNPD 578,169 551,493 26,676 2,944 29.620
722 B2 3.546.007 3,433,867 112,141 3,072 115,212
723
724 Total Distribution Expense B2 215,468,741 204,320,401 11,148,340 286,225 11,434,56
725
726
727 Summary of Distnbution Expense by Factor
728 S 164,003,397 155,229,589 8.773,808 202,757 8,976.565
729 SNPD 51,465,344 49,090,812 2.374.532 83,467 2.457.999
730
731 Total Distribution Expense by Factor 215.68,741 204.320,401 11,148.34 286,225 11,43,564
732
733 901 Supervision
734 CUST S 102,805 87,017 15,788 56 15,844
735 CUST CN 2,451,290 2,356.068 95,222 4.004 99.226
736 B2 2,554,096 2,443,085 111,010 4.060 115,070
737
738 902 Meter Readin Exnse
739 CUST S 20,750,177 19,136,393 1,613,784 62,513 1,676.297
740 CUST CN 1,770.041 1,701,283 68,758 2,274 71,033
741 B2 22.520,219 20.837,676 1,682,543 64,787 1,747,330
742
743 903 Customer Receipts & Collections
744 CUST S 7,352,86 7,023,206 329.657 10,345 340,002
745 CUST CN 48,927,462 47,026,843 1.900,620 58,841 1,959,461
746 B2 56,280,326 54.050,049 2.230,277 69,186 2.299.463
747
748 904 Uncollectible Accunts
749 CUST S 12,149,005 11.677,783 471,222 471.222
750 P SG
751 CUST CN 26.790 25.749 1.041 1.041
752 B2 12.175.795 11.703,532 472.263 472.263
753
754 905 Misc. Customer Accounts Exnse
755 CUST S 12,390 12.390
756 CUST CN 242.182 232.774 9,408 302 9,710
757 B2 254.572 245,164 9,408 302 9,710
758
759 Totl Customer Account Expense B2 93,785,007 89,279,506 4,505,501 138,335 4,643,836
760
761 Summary of Customer Acc Exp by Factor
762 S 40,367,241 37,936,789 2.43,452 72,914 2,503.366
763 CN 53,417,766 51,342,717 2.075,049 65,421 2,140.470
764 SG
765 Total Customer Accounts Expense by Factor 93,785,007 89,279,506 4.505,501 138,335 4,643.836
766
767 907 Supervision
768 CUST S
769 CUST CN 286,417 275,290 11,126 396 11,523
770 B2 286,417 275.290 11,126 396 11.523
771
772 908 Customer Assistance
773 CUST S 63,240,907 56,710.070 6,530,837 (4,992,585)1,538,252
774 CUST eN 2,861,099 2,749.957 111,141 4,430 115.571
775
776
777 B2 66.102,006 59,46.027 6,641.979 (4,988.155)1.653,823
778
ROLLED-IN Page 9.13
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
779 909 Informational & Instructional Adv
780 CUST S 349,724 349,124
781 CUST CN 4,574,542 4,396,841 177,701 (1,426)176,275
182 62 4,924,261 4,146.566 177,701 (1,426)116,215
783
784 910 Misc. Customer Service
185 CUST S
186 CUST CN 150,055 144,226 5,829 8 5,831
181
788 62 150,055 144,226 5,829 8 5,831
789
790 Total Customer Service Expense B2 71,462,744 64,626,109 6,836,635 (4,989,177)1,847,458
191
192
193 Summary of Customer Service Exp by Factor
194 S 63,590,631 57.059,794 6,530,831 (4,992,585)1,538,252
795 CN 7,872,112 1,566.315 305,791 3,08 309,206
796
797 Total Customer Service Expense by Factor 62 71,462.744 64,626.109 6,836,635 (4.989,17)1,847,45
198
199
800 911 Supervision
801 CUST S
802 CUST CN
803 62
804
805 912 Demonstration & Sellng Expense
806 CUST S
807 CUST CN
808 62
809
810 913 Actvertising Expense
811 CUST S
812 CUST CN
813 62
814
815 916 Misc. Sales Expense
816 CUST S
817 CUST CN
818 62
819
820 Total Sales Expense 62
821
822
823 Total Sales Expense by Factor
824 S
825 CN
826 Total Sales Expense by Factor
821
828 Total Customer Service Exp Including Sales B2 71,462,744 64,626,109 6,836,635 (4,989,177)1,847,458
829 920 Administrtive & General Salaries
830 PTO S (4,135,538)(5,140.020)1,004,482 (1,004,482)
831 CUST CN
832 PTO SO 77,010,359 72,856,271 4,154,087 180,879 4,334.967
833 82 72,874,820 67,716,251 5,158,569 (823,603)4,334.967
834
835 921 Offce Supplies & expnses
836 PTD S (568.262)(568,12)150 150
837 CUST CN
838 PTO SO 11,599,349 10,973,658 625,691 (31,329)594,362
839 62 11.031,087 10,405,246 625,841 (31,329)594,512
84
841 922 A&G Expenses Transferrd
842 PTO S84CUSTCN84PTOSO (25,86,776)(24,471,472)(1.395,304)69,039 (1,326,265)
845 62 (25,866,776)(24,471,472)(1,395,304)69.039 (1,326,265)
846
ROLLED.IN Page 9.14
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
847 923 Outside Services
848 PTD 5 630 630
849 CUST CN
850 PTD SO 11.038;720 10,443.270 595,450 (25.996)569,454
851 82 11,039.350 10,443.900 595,450 (25.996)569.454
852
853 924 Propert Insurance
854 PTD SO 23.970.318 22.677.312 1.293.005 1.293.005
855 82 23.970,318 22.677,312 1,293.005 1,293.005
856
857 925 Injuiies & Damages
858 PTD SO 7,434.336 7,033.313 401,022 113,482 514,505
859 82 7.434.336 7.033.313 401.022 113.482 514.505
860
861 926 Employee Pensions & Benefits
862 LABOR S
863 CUST CN
864 LABOR SO
865 B2
866
867 927 Franchise Requirements
868 DMSC S
869 DMSC SO
870 B2
871
872 928 Regulatory Commission Expense
873 DMSC S 11,943,931 11.526.839 417.092 4.691 421.783
874 CUST CN
875 DMSC SO 2.197.338 2.078,809 118,529 78 118,607
876 FERC SG 2.323,78 2.195,489 127,989 127,989
877 82 16,464.747 15.801.137 663.610 4,769 668,379
878
879 929 Duplicate Charges
880 LABOR S
881 LABOR SO (3,420.843)(3,236.316)(184,527)(246)(184.773)
882 B2 (3,420.843)(3,236,316)(184,527)(246)(184.773)
883
884 930 Misc General Expenses
885 PTD S 5.290,870 5.282.370 8.500 196.497 204.997
886 CUST eN 4,500 4.325 175 (44)131
887 LABOR SO 14,400.017 13.623.252 776.765 2.504,559 3.281.323
888 B2 19.695.387 18.909.947 785,439 2.701,012 3,486,452
889
890 931 Rents
891 PTD 5 961,066 961,066
892 PTD SO 5.238,518 4,955,942 282.576 282.576
893 82 6.199,584 5,917.009 282.576 282.576
894
895 935 Maintenance of General Plant
896 G 5 15,577 15,577
897 CUST CN
898 G SO 23,181,924 21,931.446 1.250.478 9,942 1,260,420
899 B2 23,197,501 21.947.023 1.250,478 9,942 1.260,420
900
901 Total Administrati & General Expense B2 162,619,511 153,143,351 9,476,160 2,017,070 11,493,230
902
903 Summary of A&G Exnse by Factor
904 S 13,508,275 12,078,050 1,430,224 (803,294)626,930
905 50 146,783,259 138,865,487 7.917.772 2.820.407 10.738,180
906 5G 2,323,478 2,195.489 127,989 127,989
907 eN 4,500 4.325 175
J44)
131
908 Total A&G Exnse by Factor 162,619,511 153,143.351 9,476,160 2,017. 70 11,493.230
909
910 Totl O&M Expe 82 2,676,130,329 2,514,814,055 161,316;214 19,268,439 180,58,713
ROLLED-N Page 9.15
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
911 403SP Steam Depreciation
912 P SG 23.110.000 21,836.987 1,273,014 1,273,014
913 P SG 25,963,107 24,532,930 1,430,177 1,430,177
914 P SG 52,664,788 49.763,750 2,901,039 806,887 3.707,926
915 P SG 7,785,936 7.357,048 .428,888 428,888
916 83 109,523,832 103,490,714 6,033,118 806,887 6,840,005
917
918 403NP Nuclear Depreciation
919 P SG
920 83
921
922 403HP Hydro Depreciation
923 P SG 3.645,429 3,444.621 200,808 200,808
924 P SG 1,016,491 960,498 55,993 55,993
925 P SG 7,347,198 6,942,478 404,720 24,768 429,488
926 P SG 3,441,241 3,251,681 189,561 189,561
927 83 15,450,360 14,599,277 851,083 24,768 875,850
928
929 4030P Other Production Depreciation
930 P SG 124,817 117,942 6,876 6,876
931 P SG 94,515,821 89,309,419 5,206,402 1,032,439 6,238,841
932 P SG 2,544,778 2,404,599 140,179 140,179
933 P SG
934 83 97,185,416 91,831.959 5,353,457 1,032,439 6,385.895
935
936 403TP Transmission Depreciation
937 T SG 11,260,768 10,640,469 620,299 620,299
938 T SG 12,574,497 11,881,831 692,666 692,666
939 T SG 39,057,941 36,906,435 2,151,506 1,182.236 3,333,741
940 83 62.893,206 59,428.735 3,464,471 1.182,236 4,646,706
941
942
943
944 403 Distribution Depreciation
945 360 La & lend Ròp"" DPW S 292,392 274,904 17,488 17,488
946 361 Sln DPW S 1,016,944 993,937 23,007 23,007
947 362 Sl Eqpmnt DPW S 17,275,368 16,659,953 615,415 615,415
948 363 __ Batlery Eo' DPW S 91,113 91,113
949 364 Poles & Towers DPW S 33,365,759 31,345,364 2,020,396 1.199 2,021,595
950 365 OH Cond DPW S 18,807,119 17.850,287 956,832 956,832
951 366 UG Cond DPW S 7,529,925 7.372.273 157,652 157,652
952 367 UG Cori DPW S 17,412,373 16,938,733 473,640 473,640
953 368 UneTrans DPW S 26,759,726 25,342,167 1,417,559 1,417,559
954 369 SÐ DPW S 11,531,258 11,013,789 517,468 517,468
955 370 Met DPW S 6,509,338 6,062,663 44,676 44,676
956 371 Inst Cua Prem DPW S 496,358 488,788 7,570 7,570
957 372 l.tM Propy DPW S
958 373 Sttl~DPW S 2,255,605 2,226,651 28.954 28,954
959 83 143,343,279 136,660,621 6,682,658 1,199 6,683,857
960
961 403GP General Depreciation
962 G-SITUS S 12.310,835 11,555,600 755,235 (173)755,062
963 PT SG 502,163 474,501 27,662 27,662
964 PT SG 706,142 667,244 38,898 38,898
965 P SE 26.236 24,568 1,668 1,668
966 CUST CN 1,759.170 1,690,834 68,336 68,336
967 G-SG SG 5,229,908 4,941,819 288,089 2,848 290.938
96 PTD SO 14,946,453 14,140.213 806,241 8,416 814,656
969 G-5G SG 6,010 5,679 331 331
970 G-5G SG 144,595 136.630 7.965 7,965
971 83 35,631.512 33.637.088 1,994,424 11.090 2.005,515
972
973 403GVO General Vehicles
974 G-SG SG
975 83
976
977 403MP Mining Deprecition
978 P SE
979 83
980
ROLLED.IN Page 9.16
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
981 403EP Expenmental Plant Depreciation
982 P SG
983 P SG
984 83
985 4031 ARO Depreciation
986 P S
987 83
988
989
990 Total Depreiation Expense B3 46,027,603 439,64,393 24,379,210 3,051,619 27,437,829
991
992 Summary S 155,654,113 148,216,221 7,437,892 1.026 7,438,918
993 DGP
994 DGU
995 SG 291.641.631 275,576,558 16.065.073 3.049,177 19,114,251
996 SO 14,946.453 14,140,213 806,241 8,416 814,656
997 CN 1.759.170 1,690,834 68,336 68.336
998 SE 26,236 24,568 1.668 1.668
999 SSGCH
1000 SSGCT
1001 Total Depreciation Expense 8y Factor 464,027,603 439,648,393 24.379.210 3.058,619 27,437,829
1002
1003 404GP Amort of L T Plant - Capital Lease Gen
1004 I-SITUS S 1.345,062 1,345,062
1005 I-SG SG
1006 PTD SO 929,374 879,242 50,132 50,132
1007 P SG
1008 CUST CN 249.571 239,876 9.695 9.695
1009 P SG
1010 84 2.524,007 2,464,180 59.827 59.827
1011
1012 404SP Amort of L T Plant - Cap Lease Steam
1013 P SG
1014 P SG
1015 B4
1016
1017 4041P Amort of L T Plant - Intangible Plant
1018 1-SITUS S 94.304 73,772 20,532 20,532
1019 P SE 14,498 13,577 922 922
1020 I-SG SG 8,952,161 8,459,032 493,130 31,188 524,318
1021 PTD SO 13,131,339 12,423.009 708,330 9.544 717,873
1022 CUST CN 5,000.879 4.806.617 194,262 194.262
1023 I-SG SG 2,615,413 2,471,343 144.070 144.070
1024 I-SG SG 310,432 293,332 17.100 17,100
1025 P SG
1026 I-SG SG
1027 I-SG SG 54,934 51.908 3,026 3,026
1028 P SG 16,758 15,835 923 923
1029 84 30,190,717 28.608.423 1,582,295 40,732 1,623,026
1030
1031 404MP Amort of L T Plant - Mining Plant
1032 P SE
1033 B4
1034
1035 4040P Amort of L T Plant - Other Plant
1036 P SG
1037 84
1038
1039
1040 404HP Amortation of Other Electnc Plant
1041 P SG 6.589 6.226 363 363
1042 P SG 40,392 38.167 2.225 2,225
1043 P SG
1044 84 46.981 44.393 2,588 2.588
1045
1046 Totl Amortization of limied Term Plant B4 32,761,706 31,116,997 1,64,710 40,732 1,685,441
1047
1048
1049 405 Amorton of Otr Elec Plant
1050 GP S
1051
1052 B4
1053
ROLLED-IN Page 9.17
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1054 406 Amortization of Plant Acquisition Adj
1055 P S
1056 P SG
1057 P SG
1058 P SG 5,479,353 5,177,523 301,830 301,830
1059 P SO
1060 84 5,479,353 5,177,523 301,830 301,830
1061 407 Amort of Prop Losses, Unrec Piant, etc
1062 DPW S (36,176)(36,176)
1063 GP SO
1064 P SG 3,479,961 3,288,268 191,694 191,694
1065 P SE
1066 P SG (191,694)(191,694)
1067 P TROJP 2,013,725 1,900.202 113.523 113,523
1068 84 5,457,511 5,152,294 305,217 (191,694)113,523
1069
1070 Total Amortzation Expense B4 43,698,570 41,446,814 2,251,756 (150,962)2,100,794
1071
1072
1073
1074 Summary of Amortzation Expense by Factor
1075 S 1,403,190 1,382,658 20,532 20,532
1076 SE 14,498 13,577 922 922
1077 TROJP 2,013,725 1,900,202 113.523 113,523
1078 DGP
1079 DGU
1080 SO 14,060.713 13,302,251 758,462 9,544 768.006
1081 SSGCT
1082 SSGCH
1083 SG-P
1084 CN 5,250,450 5,046,493 203,957 203,957
1085 SG 20.955,993 19,801,633 1,154,360 (160,506)993,855
1086 Total Amortization Expense by Factor 43.698,570 41,446,814 2,251,756 (150,962)2.100,794
1087 408 Taxes Oter Than Income
1088 OMSC S 25.320,436 25.320,436
1089 GP GPS 87.317,409 82.607,339 4.710,069 414,144 5,124.214
1090 GP SO 10,522,150 9,954,565 567.585 567.585
1091 P SE 717,492 671,877 45,615 45,615
1092 P SG
1093 DMSC OPRV-ID
1094 GP EXCTAX
1095 GP SG
1096
1097
1098
1099 Total Taxes Other Than Income B5 123,877,48 118.554;:17 5,323,269 414,144 5,737,413
1100
1101
1102 41140 Deferred Investment Tax Credit - Fed
1103 PTO OGU (1.874,204)(1,672,710)(201,494)(201,494)
1104
1105 B7 (1,874,204)(1,672.710)(201,494)(201,494)
1106
1107 41141 Deferrd Investment Tax Credit -Idaho
1108 PTO OGU
1109
1110 B7
1111
1112 Totl Deferred ITC 87 (1,874,204)(1,672,710)(201,494)(201,494)
1113
ROLLED-IN Page 9.18
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1114
1115 427 Interest on Long-Term Debt
1116 GP S (422,493)(422,493)
1117 GP SNP 369,236,117 349,622,675 19,613,443 19,613,443
1118 B6 369,236,117 349,622,675 19,613,443 (422,493)19,190,950
1119
1120 428 Amortization of Debt Disc & Exp
1121 GP SNP 6,571,354 6,222,290 349,064 349,064
1122 B6 6,571,354 6,222,290 349,064 349,064
1123
1124 429 Amortization of Premium on Debt
1125 GP SNP (2,718)(2,574)(144)(144)
1126 B6 (2,718)(2,574)(144)(144)
1127
1128 431 Other Interest Expense
1129 NUTIL OTH
1130 GP SO
1131 GP SNP 10,264.106 9.718,887 545,219 545,219
1132 B6 10,264,106 9,718,887 545,219 545,219
1133
1134 432 AFUDC - Borrwed
1135 GP SNP (35,186,532)(33,317,459)(1,869.072)(1,869.072)
1136 (35,186,532)(33.317,459)(1,869,072)(1,869,072)
1137
1138 Total Elec, Interest Deductions for Tax B6 350,882,327 332,243,819 18,638,508 (422,493)18,216,015
1139
1140 Non-Utilty Portion of Interest
1141 427 NUTIL NUTIL
1142 428 NUTIL NUTtL
1143 429 NUTIL NUTIL
1144 431 NUTIL NUTIL
1145
1146 Total Non-utilit Interest
1147
1148 Total Interest Deductions for Tax B6 350,882.327 332,243,819 18.638,508 (422,493)18,216,015
1149
1150
1151 419 Interest & Dividends
1152 GP S
1153 GP SNP
163,955.322)
(60,558,081l (3,397,241 )160,278 (3,236.963)
t154 Total Operating Deductions for Tax B6 63.955.322)(60,558,081 (3,397,241 )166,278 (3,236,963)
1155
1156
1157 41010 Deferred Income Tax. Federal-DR
1158 GP S 26,529,700 26,102,344 427.356 (347,371)79,985
1159 P TROJD 735,881 694,228 41.653 41,653
1160 P SG 26,126 24,887 1,439 1,439
1161 LABOR SO 37,814,180 35,774,410 2,039,770 (276,27)1,763,743
1162 GP SNP 35,849,593 33,945.299 1,904,294 1,904,294
1163 P SE 23,499,301 22,005,328 1,493,973 206,834 1,700,807
1164 PT SG 51.291,699 48,466,297 2,825,402 17,727,662 20,553,064
1165 GP GPS 31,266,440 29,579,868 1,686,572 1,666,572
1166 TAXEPR TAXEPR 615,608,170 584,405,196 31,202,974 31,202,974
1167 CUST BADDEBT 44,332 426,136 17,196 17,196
1168 CUST CN 22,893 22,004 889 889
1169 P IBT 348,313 321,435 26,878 (26,878)
1170 DPW SNPD 67,978 64.842 3,136 3,136
1171 B7 823,503,60 781,832,074 41,671,532 17.284,221 58,955.752
1172
ROLLED-IN Page 9.19
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1173
1174
1175 41110 Deferred Income Tax - Federal-CR
1176 GP S (26.854,405)(25.660,209)(1,194,196)322,685 (871,511)
1177 P SE (17,99,483)(16,855,162)(1.144,321)233.209 (911,112)
1178 P SG (538.368)(508,712)(29,656)(29,656)
1179 GP SNP (31,616.890)(29,937,433)(1,679,457)(1,679,457)
1180 PT SG (7,932,473)(7,495.513)(436,960)(1.082,112)(1,519.072)
1181 DPW CIAC (20,332,44)(19,394,336)(938,108)(938,108)
1182 LABOR SO (28,202,710)(26,681,401 )(1,521,309)(5,507)(1,526,816)
1183 PT SNPD (1,949,167)(1,859,235)(89,932)(89,932)
1184 CUST BADDEBT
1185 P SGCT (356,221)(336,523)(19,698)(19,698)
1186 BOOKDEPR SCHMDEXP (203,344,850)(192,661,462)(10,683,388)(10.683,388)
1187 P TROJD (1,332,481)(1,257,059)(75,22)(75.22)
1188 P IBT (427,931)(394,909)(33,022)33,022
1189
1190
1191 B7 (340,887,423)(323.041.956)(17,845,467)(498,703)(18,344,170)
1192
1193 Total Deferred Income Taxes B7 482,616,183 458,790,118 23,826,065 16,785,518 40,611,583
1194 SCHMAF Additions - Flow Through
1195 SCHMAF S
1196 SCHMAF SNP
1197 SCHMAF SO
1198 SCHMAF SE
1199 SCHMAF TROJP
1200 SCHMAF SG
1201 B6
1202
1203 SCHMAP Additions - Permanent
1204 P S 20,000 20,000
1205 P SE 90.872 85,095 5,777 5,777
1206 LABOR SNP
1207 SCHMAP-SO SO 12,568,198 11,890,245 677.953 677,953
1208 SCHMAP SG
1209 DPW SADDEST
1210 B6 12,679,071 11,995.341 683,730 683.730
1211
1212 SCHMAT Additions. Temporary
1213 SCHMA T -S1T S 57,590,033 56,886,057 703,976 (591,588)112,388
1214 P SG
1215 DPW CIAC 53,575,515 51,103,623 2,471.892 2,471,892
1216 SCHMAT -SNP SNP 83,309,767 78.884,438 4,425,329 4,425,329
1217 P TROJD 1,572,028 1,483,047 88.981 88,981
1218 P SGCT 938,633 886,730 51,903 51,903
1219 SCHMAT-SE SE 27.051,042 25.331,266 1,719,776 (13,920)1.705.856
1220 P SG 20,901.884 19.750,504 1,151,380 2,850,842 4.002,222
1221 CUST CN
1222 SCHMAT-SO SO 23,130,941 21,883.214 1,247,728 14,511 1,262,239
1223 SCHMA T -SNP SNPD 5,136,011 4,899,043 236,968 236,968
1224 DPW BADDEST
1225 P SG
1226 BOOKDEPR SCHMDEXP 535.808,937 507,658,460 28,150,477 28,150,477
1227 B6 809,014,791 768,766,383 40,248,409 2,259,845 42.508,254
1228
1229 TOTAL SCHEDULE - M ADDITIONS B6 821,693,862 780,761,724 40,932.139 2,259,845 43,191,984
1230
ROLLED-IN Page 9.20
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1231 SCHMDF Deductions - Flow Through
1232 SCHMDF S
1233 SCHMDF DGP
1234 SCHMDF DGU
1235 B6
1236 SCHMDP Deductions. Permanent
1237 SCHMDP S 904 904
1238 P SE 840,899 787,439 53,460 53,460
1239 PTD SNP 381,063 360.822 20,242 20.242
1240 SCHMDP IBT
1241 P SG
1242 SCHMDp.SO SO 26,365,079 24.942,895 1,422,183 1,422,183
1243 B6 27,587,945 26,092.060 1,495,885 1,495,885
1244
1245 SCHMDT Deductions. Temporary
1246 GP S 39,346,405 38,274,657 1,071,748 (915.314)156,434
1247 DPW BADDEBT 1,168,170 1,122,860 45,310 45,310
1248 SCHMDT -SNP SNP 94,462,842 89,44,073 5,017,769 5,017.769
1249 SCHMDT CN 60,323 57,980 2,343 2.343
1250 SCHMDT SG 68,842 65,050 3.792 3,792
1251 CUST DGP
1252 P SE 41,542,935 38.901,834 2,641,101 1,145,582 3,786,683
1253 SCHMDT -SG SG 135,152,429 127,707,560 7,444,869 48,711,480 54,156,349
1254 SCHMDT .GP!: GPS 82,386,340 77,942,262 4,444,078 4,444,078
1255 SCHMDT -SO SO 48,456,951 45,843,090 2,613,861 (1,054.375)1,559,486
1256 TAXDEPR TAXDEPR 1.622,113,173 1,539,894,065 82.219.108 82,219,108
1257 DPW SNPD 179,120 170,856 8,264 8,264
1258 B6 2,064,937,530 1,959,425,286 105,512,244 . 45,887,373 151,399,617
1259
1260 TOTAL SCHEDULE. M DEDUCTIONS B6 2,092,525,475 1,985.517,346 107,008,129 45.887,373 152,895,503
1261
1262 TOTAL SCHEDULE - M ADJUSTMENTS B6 (1,270,831,613)(1,204,755,622)(66,075,991)(43,627,528)(109,703,519)
1263
1264
1265
1266 40911 State Income Taxes
1267 1ST 1ST (21,767,423)(20,087,707)(1,679,716)(1,724.838)(3,404,554)
1268 IBT SE
1269 PTC P SG (70,472)(70,472)
1270 IBT 1ST
1271 Total State Tax Expense (21.767.423)(20,087,707)(1.679,716)(1,795,311)(3.475,027)
1272
1273
1274 Calculation of Taxable Income:
1275 Operating Revenues 4,353,766,380 4,117,757.584 236,008,796 27,679,324 263,688,120
1276 Operating Deductions:
1277 o & M Exnses 2,676,130.329 2,514.814.055 161.316,274 19,268,439 180,584.713
1278 Depreciation Expense 464,027,603 439,648,393 24,379.210 3,058,619 27,437,829
1279 Amortizatin Expense 43,698,570 41,44,814 2,251,756 (150,962)2,100,794
1280 Taxes Other Than Income 123,877 ,487 118,554,217 5.323,269 414,144 5,737,413
1281 Interest & Dividends (AFUDG-Equity)(63,955,322)(60,558,081 )(3,397,241)160,278 (3,236,963)
1282 Misc Revenue & Expense (5,975,707)(5,678,965)(296,742)(284,193)(580,935)
1283 Total Operating Deductons 3,237,802,959 3,048.226,433 189,576,526 22,466,325 212,042,851
1284 Oter Deuctons:
1285 Interest Deductions 350,882,327 332.243,819 18.638,508 (422,493)18,216,015
1286 Interest on PCRBS
1287 Schedule M Adjustments (1,270,831.613)(1,204,755,622)(66,075,991 )(43,627,528)(109,703,519)
1288
1289 Income Before State Taxes (505,750,519)(467,468.29)(38,282.229)(37,992.036)(76.274,265)
1290
1291 State Income Taxes (21,767,423)(20,087,707)(1,679.716)(1,795,311)(3,475.027)
1292
1293 Total Taxable Income (483,983,096)(447.380,583)(36.602.513)(36,196,725)(72,799,238)
1294
1295 Tax Rate 35.0%35.0%35.0%35.0%35.0%
1296
1297 Federal Income Tax - Calculated (169,394,084)(156,58,204)(12,810,880)(12.668,854)(25,479,733)
1298
1299 Adjustments to Calcued Tax:
1300 40910 PMI P SE
1301 40910 REC P SG (3,821.447)(3,821,447)
1302 40910 P SO
1303 40910 IRS_LAR S
1304 Federl Income Tax Expense (169.394.081 (156,583.204)(12,810.880)(16,49,301)(29,301,181 )
1305
1306 Totl Operating Expees 3.591,338,753 3,389,231,011 202,107,742 20.805,953 22.913.695
ROLLED-IN Page 9.21
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1307 310 Land and Land Rights
1308 P SG 2.329,517 2.201.196 128,321 128.321
1309 P SG 34.798,446 32.881.574 1,916,872 1.916.872
1310 P SG 56.303.435 53.201.961 3.101.474 3.101,474
1311 P S
1312 P SG 2,448.255 2,313.393 134.862 134,862
1313 88 95.879.653 90,598.124 5.281,529 5.281.529
1314
1315 311 Structures and Improvements
1316 P SG 234.107,411 221.211.609 12.895.802 12,895.802
1317 P SG 325,036.982 307.132,327 17.904.655 17.904.655
1318 P SG 221,770,821 209.554.580 12.216.241 12,216.241
1319 P SG 57,386.063 54.224.953 3.161.110 3.161.110
1320 88 838,301,276 792.123.46 46.177.808 46.177.808
1321
1322 312 Boiler Plant Equipment
1323 P SG 698.182,038 659,722.695 38.459.343 38.459,343
1324 P SG 658.624.890 622.344.552 36.280,338 36.280.338
1325 P SG 1,442,122.538 1,362.683.248 79.439.290 32.187.338 111,626.628
1326 P SG 325,425,382 307,499.331 17.926,050 17.926.050
1327 88 3.124.354.846 2.952.249.826 172.105.022 32.187.338 204.292.360
1328
1329 314 Turbogenerator Units
1330 P SG 139.149.055 131,484.032 7.665.023 7.665.023
1331 P SG 141.986.218 134.164.910 7.821.308 7.821.308
1332 P SG 487.922.642 461.045,433 26,877.209 26.877.209
1333 P SG 63,734.933 60.224.096 3,510.837 3.510.837
1334 88 832,792,846 786.918,471 45.874.377 45.874.377
1335
1336 315 Accessory Electric Equipment
1337 P SG 87.739.621 82.906,86 4.833.135 4.833.135
1338 P SG 138.674,494 131.035.612 7.638,882 7.638,882
1339 P SG 74.099.755 70.017.971 4.081.783 4.081.783
1340 P SG 66.352.508 62.697,482 3.655.027 3.655.027
1341 B8 366,866.378 346.657.551 20.208.827 20.208.827
1342
1343
1344
1345 316 Mise Power Plant Equipment
1346 P SG 4.786.846 4.523.164 263.683 263.683
1347 P SG 5.245.086 4.956,160 288.925 288.925
1348 P SG 15,109.785 14.277.463 832.322 832.322
1349 P SG 4.037.788 3.815.366 222,421 222,421
1350 88 29.179.506 27.572.154 1.607.352 1.607.352
1351
1352 317 Steam Plant ARO
1353 P S
1354 B8
1355
1356 SP Unclassified Steam Plant - Account 300
1'357 P SG 787.304 743.936 43.369 43.369
1358 88 787.304 743.936 43.369 43.369
1359
1360
1361 Total Steam Production Plant 88 5,288,161,813 4,996,863,530 291,298,283 32,187,338 323,485,622
1362
1363
1364 Summary of Steam Producion Plant by Factor
1365 S
1366 DGP
1367 DGU
1368 SG 5.288.161,813 4.996.863.530 291,298.283 32,187.338 323,485,622
1369 SSGCH
1370 Total Steam Proucn Plant by Factor 5.288.161.813 4.99.863.530 291.29.283 32.187.33 323.485.622
1371 320 Land and Land Rights
1372 P SG
1373 P SG
1374 88
1375
1376 321 Struures and Improvements
1377 P SG
1378 P SG B8
1379
ROLLED-IN Page 9.22
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1380
1381 322 Reactor Plant Equipment
1382 P SG
1383 P SG
1384 68
1385
1386 323 Turbgenerator Units
1387 P SG
1388 P SG
1389 68
1390
1391 324 Land and Land Rights
1392 P SG
1393 P SG
1394 68
1395
1396 325 Misc. Power Plant Equipment
1397 P SG
1398 P SG
1399 B8
1400
1401
1402 NP Unclassified Nuclear Plant. Acct 300
1403 P SG
1404 B8
1405
1406
1407 Total Nuclear Production Plant B8
1408
1409
1410
1411 Summary of Nuclear Producton Plant by Factor
1412 DGP
1413 DGU
1414 SG
1415
1416 Total Nuclear Plant by Factor
1417
1418 330 Land and Land Rights
1419 P SG 10.621.118 10.036,054 585,064 585,064
1420 P SG 5.270.019 4.979,720 290,299 290,299
1421 P SG 3,645.604 3,44,786 200,818 200,818
1422 P SG 672,873 635,808 37,065 37,065
1423 68 20,209,614 19.096.368 1,113,246 1,113,246
1424
1425 331 Structures and Improvements
1426 P SG 21.272.790 20.100,979 1,171.811 1,171,811
1427 P SG 5.299.236 5,007,327 291,908 291.908
1428 P SG 69,738,251 65,896,721 3.841,530 3,841,530
1429 P SG 7,984,198 7,544.388 439.809 439,809
1430 68 104.294,475 98.549,416 5,745,059 5.745,059
1431
1432 332 Reservoirs, Dams & Waterways
1433 p SG 151.296.614 142,962.443 8.334.171 8,334,171
143 P SG 20,156,916 19,046.572 1.110.343 1,110,343
1435 P SG 106.245,543 100.393.009 5.852.534 336,976 6,189,509
1436 P SG 37.108,148 35.064,047 2,044.102 2.044.102
1437 68 314,807,221 297.466;072 17,341,149 336.976 17.678,125
1438
1439 333 Water Wheel, Turbines, & Generators
1440 p SG 31,913,924 30,155.946 1,757,978 1,757.978
1441 p SG 8,828,844 8,342.508 486,337 486,337
1442 P SG 43.462,254 41.068,137 2.394,117 2,394,117
144 p SG 27.234.682 25,734,460 1,500.222 1.500,222
144 68 111.439.704 105,301,050 6.138,654 (1,138.654
144
1446 334 Accssory Elecc Equipment
1447 p SG 4,430,934 4,186.857 244,078 244.078
144 p SG 3,669.976 3.467.816 202,161 202,161
1449 P SG 43.817.031 41,403.370 2,413.660 2,413,660
145 P SG 7.133.812 6,740.846 392.966 392.966
1451 B8 59.051.753 55,798.888 3.252.865 3.252,865
1452
ROLLED-IN Page 9.23
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DE SCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1453
1454
1455 335 Misc. Power Plant Equipment
1456 P SG 1,197,194 1,131.247 65,947 65,947
1457 P SG 186,194 175,938 10,257 10,257
1458 P SG 996.385 941,499 54,886 54.886
1459 P SG 11.353 10,728 625 625
1460 B8 2,391,127 2,259,411 131,715 131,715
1461
1462 336 Roads, Railroads & Bridges
1463 P SG 4,620,060 4,365,564 254,496 254,496
1464 p SG 828.931 783.269 45,662 45,662
1465 P SG 9,817,317 9,276,530 540.787 540,787
1466 P SG 682.347 644,760 37,587 .37,587
1467 B8 15.948,654 15,070.123 878.531 878.531
1468
1469 337 Hydro Plant ARO
1470 p S
1471 B8
1472
1473 HP Unclassified Hydro Plant. Acct 300
1474 P S
1475 P SG
1476 P SG
1477 P SG
1478 B8
1479
1480 Total Hydraulic Production Plant B8 628,142,54 593,541,329 34,601,219 336,976 34,938,195
1481
1482 Summary of Hydraulic Plant by Factor
1483 S
1484 SG 628,142,548 593,541,329 34.601,219 336,976 34,938,195
1485 DGP
1486 DGU
1487 Total Hydraulic Plant by Factor 628,142.548 593,541,329 34,601,219 336.976 34.938.195
1488
1489 $40 Land and Land Rights
1490 P SG 23,516,708 22.221.290 1,295,417 1.295,417
1491 P SG
1492 P SG
1493 B8 23.516,708 22.221,290 1.295,417 1,295,417
1494
1495 341 Strctures and Improvements
1496 P SG 151.043.941 142,723,688 8,320.252 8.320.252
1497 P SG 163.512 154.505 9,007 9.007
1498 P SG 4,241,952 4,008.284 233.66 233.668
1499 B8 155,449.405 146,886,477 8.562.927 8.562,927
150
1501 342 Fuel Holders, Producers & Accessories
1502 P SG 8,06,209 7.943.153 463.056 46,056
1503 P SG 121.339 114.655 6.684 6,684
1504 P SG 2.284,126 2.158,305 125,821 125.821
1505 B8 10.811.674 10.216.113 595,561 595.561
1506
1507 343 Prime Movers
1508 P S
1509 P SG 754.46 712.906 41.560 41,560
1510 P SG 2.223.358.082 2.100.884.449 122,473.63 13.942.359 136,415.992
1511 P SG 51.744.608 48.894,258 2.850.351 2,850,351
1512 B8 2,275.857.156 2,150.491.612 125.365.54 13.942.359 139,307,903
1513
1514 344 Generators
1515 p S
1516 P SG
1517 P SG 331.535.449 313.272.825 18.262,623 18.262,623
1518 P SG 15.873,643 14.999.244 874.399 874.399
1519 68 347.409.092 328.272,070 19.137,023 19.137.023
ROLLED.IN Page 9.24
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP.FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1520
1521 345 Accessory Electric Plant
1522 P SG 226,854,809 214,358,517 12,496,292 12,496,292
1523 P SG 156.586 147.961 8,626 8.626
1524 P SG 2.919.649 2.758.820 160,829 160.829
1525 68 229.931.044 217.265.297 12,665,747 12,665.747
1526
1527
1528
1529 346 Misc. Power Plant Equipment
1530 P SG 12.167.872 11,497.605 670,267 670.267
1531 P SG 11.813 11.162 651 651
1532 68 12.179.685 11.508.767 670,918 670.918
1533
1534 347 Other Production ARC
1535 P S
1536 68
1537
1538 OP Unclassified Other Prod Plant-Acct 300
1539 P S
1540 P SG
1541
1542
1543 Total Other Production Plant B8 3,055,154,764 2,886,861,627 168,293,136 13,942,359 182,235,495
154
1545 Summary of Other Production Plant by Factor
1546 S
1547 DGU
1548 SG 3,055,154,764 2.886,861.627 168,293,136 13,942,359 182.235,495
1549 SSGCT
1550 Total of Other Production Plant by Factor 3,055,154.764 2,886,861.627 168.293,136 13,942,359 182.235.95
1551
1552 Experimental Plant
1553 103 Experimental Plant
1554 P SG
1555 Totâl Experimental Production Plant B8
1556
1557 Total Production Plant B8 8.971,59,125 8,477 ,266.486 49,192,639 46,466,673 54,659.312
1558 350 Land and Land Rights
1559 T SG 21,145,733 19.980.920 1.164,812 1.164.812
1560 T SG 48.501,155 45,829.470 2,671,685 2.671,685
1561 T SG 31,414,150 29,683,702 1,730,44 (23,847)1,706,601
1562 68 101,061.037 95,494,092 5,566.945 (23,847)5,543,098
1563
1564 352 Structures and Improvements
1565 T S
1566 T SG 7,741,609 7,315,163 426,446 426.44
1567 T SG 18.157,495 17,157.289 1,000,205 1,000.205
1568 T SG 59,577575 56,295.746 3,281,829 3,281,829
1569 88 85,76,679 80,768,198 4,708.481 4,708,481
1570
1571 353 Station Equipment
1572 T SG 129,985,618 122.825,363 7,160.255 7,160.255
1573 T SG 188.825.398 178,423.955 10,401,443 10,401.443
1574 T SG 988,38,505 933.939,365 54,445,140 54,445,140
1575 88 1.307.195.521 1,235.188.683 72.006,838 72.006.838
1576
1577 354 Towers and Fixtures
1578 T SG 156.322.773 147.711.736 8,611,037 8,611.037
1579 T SG 127.544,198 120.518,428 7,025,769 7.025,769
1580 T SG 165.062.634 155.970.163 9,092,472 9.092,472
1581 88 44.929,605 424.200.327 24.729.278 24.729,278
1582
1583 355 Poles and Fixres
1564 T SG 66.244.763 62.595.672 3,49.091 3.649.091
1585 T SG 117.745.408 111.259,405 6,86,003 6,486.003
1586 T SG 375.30.433 354.627.017 20.673.417 52,049.298 72.722.715
1587 88 559.290,604 528.482.093 30,808.511 52.049.298 82.857.810
1588
ROLLED-IN Page 9.25
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1589 356 Clearing and Grading
1590 T SG 197.260,339 186,394,257 10,866,082 10,866,082
1591 T SG 156,882,468 148,240,600 8,641,867 8,641,867
1592 T SG 380.070.379 359,134,210 20,936,169 20,936,169
1593 88 734.213,185 693,769,067 40,444,118 40,444,118
1594
1595 357 Underground Conduit
1596 T SG 6,371 6,020 351 351
1597 T SG 91,651 86,602 5,049 5,049
1598 T SG 3,113,807 2,942.283 171,524 171.524
1599 88 3,211.828 3,034,905 176.923 176,923
1600
1601 358 Underground Conductors
1602 T SG
1603 T SG 1,087,552 1.027,644 59,908 59,908
1604 T SG 6.442,172 6.087,305 354,867 354.867
1605 88 7.529.724 7,114,949 414,775 414,775
1606
1607 359 Roads and Trails
1608 T SG 1,863,032 1,760,406 102,625 102,625
1609 T SG 440,513 416,248 24,266 24,266
1610 T SG 9,151,569 8,647,455 504,114 504,114
1611 88 11,455,113 10,824,109 631,005 631,005
1612
1613 TP Unclassified Trans Plant - Acct 300
1614 T SG 84,550.623 79,893,154 4,657,469 4,657,469
1615 88 84,550,623 79,893,154 4,657.469 4,657,469
1616
1617 TSO Unclassified Trans Sub Plant - Acct 300
1618 T SG
1619 88
1620
1621 Total Transmission Plant 88 3,342,913,921 3,158,769,577 184,144,34 52,025,451 236,169,795
1622 Summary of Transmission Plant by Factor
1623 DGP
1624 DGU
1625 SG 3,342,913,921 3,158,769,577 184,144,344 52.025,451 236,169,795
1626 Total Transmission Plant by Factor 3.342,913,921 3,158,769,577 184,144,344 52,025,451 236,169,795
1627 360 Land and Land Rights
1628 DPW S .51,856,326 50,519,585 1,336,741 1,336,741
1629 B8 51,856,326 50,519,585 1,336,741 1,336,741
1630
1631 361 Structures and Improvements
1632 DPW S 66,495,517 65,002,256 1,493,261 1,493,261
1633 B8 66,495,517 65,002.256 1,493,261 1,493,261
1634
1635 362 Station Equipment
1636 DPW S 787,676,940 761,044,499 26,632,441 26,632,441
1637 B8 787.676,940 761 ,044,499 26,632,441 26,632,441
1638
1639 363 Storage Battery Equipment
1640 DPW S 1,457,805 1,457,805
1641 88 1,457,805 1,457,805
1642
164 364 Poles. Towers & Fixtures
1644 DPW S 903.958,177 842,950,744 61,007,433 61,007,433
1645 B8 903,958,177 842,950,744 61,007,433 61,007,433
164
1647 365 Overhead Conducors
164 DPW S 631,378,730 597,455,532 33,923,198 33,923,198
1649 B8 631,378,730 597,455,532 33,923,198 33,923,198
1650
ROLLED-lN Page 9.26
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1651 366 Underground Conduit
1652 DPW S 290,621,174 283.247,994 7.373,179 7,373,179
1653 B8 290.621.174 283,247.994 7,373,179 7.373,179
1654
1655
1656
1657
1658 367 Underground Conductors
1659 DPW S 697,799,779 674,120,851 23,678.928 23.678,928
1660 B8 697,799,779 674.120,851 23,678.928 23,678,928
1661
1662 368 Line Transformers
1663 DPW S 1.056,509.849 990.583,151 65,926.697 65.926,697
1664 B8 1,056,509,849 990,583,151 65.926.697 65,926,697
1665
1666 369 Services
1667 DPW S 559.763.102 531,874,191 27,888,911 27,888,911
1668 B8 559,763,102 531.874.191 27,888,911 27,888,911
1669
1670 370 Meters
1671 DPW S 187,209.616 173.388,196 13,821,420 13,821,420
1672 B8 187,209.616 173,388,196 13.821,420 13,821,420
1673
1674 371 Installations on Customers' Premises
1675 DPW S 8,809,120 8,644,004 165,115 165.115
1676 B8 8,809,120 8.644.004 165,115 165.115
1677
1678 372 Leased Properl
1679 DPW S
1680 B8
1681
1682 373 Street Lights
1683 DPW S 62.885.404 62,283,269 602,135 602,135
1684 B8 62.885,404 62,283,269 602,135 602,135
1685
1686 DP Unclassified Dist Plant - Acct 300
1687 DPW S 20,216,252 19,291,256 924.997 924.997
1688 B8 20.216,252 19,291,256 924.997 924.997
1689
1690 DSO Unclassified Dist Sub Plant - Acct 300
1691 DPW S
1692 B8
1693
1694
1695 Total Distribution Plant B8 5,326,637,791 5,061,863,333 264,774,458 264,774,458
1696
1697 Summary of Distnbution Plant by Factor
1698 S 5,326,637.791 5.061.863,333 264,774,458 264,774,458
1699
1700 Total Distribution Plant by Factor 5.326.637,791 5,061,863,333 264.174,458 264,774,458
ROLLED-IN Page 9.27
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1701 389 Land and Land Rights
1702 G-SITUS S 9,472,275 9,274,636 197,639 197.639
1703 GUST GN 1,128,506 1,084,668 43,838 43,838
1704 PT SG 332 314 18 18
1705 G-SG SG 1,228 1.160 68 68
1706 PTD SO 5,598.055 5,296,085 301,970 301,970
1707 B8 16,200,395 15,656,863 543,532 543,532
1708
1709 390 Structures and Improvements
1710 G-SITUS S 111.200,704 101,422.380 9,778,324 9,778,324
1711 PT SG 358,127 338,400 19,727 19,727
1712 PT SG 1,653,732 1,562,636 91,096 91,096
1713 GUST GN 12,319,587 11,841,025 478,563 478,563
1714 G-5G SG 3,675,782 3,473,302 202,480 202,480
1715 PTD SO 102.313.681 96,794,683 5,518,997 5,518,997
1716 B8 . 231.521,614 215,32,426 16,089,188 16,089,188
1717
1718 391 Offce Furniture & Equipment
1719 G-5ITUS S 13,065,614 12,137.233 928,381 928,381
1720 PT SG 1,046 988 58 58
1721 PT SG 5.295 5,003 292 292
1722 GUST GN 8,685,337 8,347,949 337,388 337,388
1723 G-5G SG 4,784,588 4,521,029 263,559 263,559
1724 P SE 97,829 91,609 6,219 6,219
1725 PTD SO 54,551,124 51,608,531 2.942,593 2,942,593
1726 G-5G SG 74,351 70,256 4,096 4,096
1727 G-5G SG
1728 88 81.265,184 76.782.599 4,482,585 4,482,585
1729
1730 392 Transportation Equipment
1731 G-5ITUS S 73,113,164 68,190,669 4,922,495 4,922,495
1732 PTD SO 7,996,779 7,565,417 431,362 4~1.362
1733 G.SG SG 17,254,817 16,304,336 950,481 950,481
1734 GUST GN
1735 PT SG 838,181 792,010 46.171 46,171
1736 P SE 404,148 378,454 25.694 25,694
1737 PT SG 120,286 113,660 6.626 6,626
1738 G.SG SG 374,178 353,567 20,612 20,612
1739 PT SG 44,655 42,195 2,460 2,460
1740 88 100,146,208 93,740,308 6,405,900 6.405,900
1741
1742 393 Stores Equipment
1743 G-SITUS S 8,861,339 8,312,757 548,582 548,582
1744 PT SG 108,431 102,458 5,973 5,973
1745 PT SG 36,03 340,229 19,834 19,834
1746 PTD SO 44,293 421,273 24,020 24,020
1747 G-G SG 4,062.155 3,838,392 223,764 223,764
1748 PT SG 53,971 50,998 2,973 2,973
1749 88 13,891,252 13,066,106 825,146 825,146
ROLLED-IN Page 9.28
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1750
1751 394 Tools, Shop & Garage Equipment
1752 G-SITUS S 32,024,394 30,281,765 1,742,629 1,742,629
1753 PT SG 2.120.983 2.004.148 116.834 116.834
1754 G-SG SG 20,499,259 19.370,058 1,129.201 1,129.201
1755 PTD SO 3.986.801 3,771,746 215,056 215.056
1756 P SE 7,106 6.655 452 452
1757 PT SG 2.176.302 2,056,20 119.882 119.882
1758 G-G SG 1.716,105 1.621.573 94.532 94,532
1759 G-SG SG 89,913 84.961 4.953 4,953
1760 B8 62.620,863 59,197.325 3,423,538 3,423.538
1761
1762 395 Laboratory Equipment
1763 G-SITUS S 25.228,787 23.956.655 1,272.132 1,272,132
1764 PT SG 20.622 19,486 1,136 1,136
1765 PT SG 13,281 12.550 732 732
1766 PTD SO 5.197.970 4.917.581 280.389 280.389
1767 P SE 7.593 7.111 483 483
1768 G-SG SG 6.353,527 6.003,543 349,984 349,984
1769 G-SG SG 253,001 239.064 13,937 13,937
1770 G-SG SG 14,022 13,249 772 772
1771 B8 37,088,802 35,169.239 1.919.564 1,919,564
1772
1773 396 Power Operated Equipment
1774 G-SITUS S 94,279,509 87,117.887 7.181.622 7.161.622
1775 PT SG 845.108 798,555 46.553 46,553
1776 G-SG SG 31.633,038 29.890,533 1.742,505 1,742,505
1777 PTD SO 1,410.640 1,334.54 76,03 76,093
1778 PT SG 1.664,492 1.572.804 91.689 91,689
1779 P SE 73.823 69,130 4,693 4,693
1780 P SG
1781 G-SG SG 968.906 915.534 53,372 53,372
1782 B8 130.875.517 121.698.990 9,176.527 9.176,527
1783 397 Communication Equipment
1784 COM_EO S 101.721.635 96.539,236 5.182.399 5,182,399
1785 COM_EO SG 4,816,644 4,551,319 265.325 265.325
1786 COM_EO SG 9,615,788 9.086.102 529.685 529,685
1787 COM_EO SO 48,166,017 45.567,850 2,598.168 2,598,168
1788 COM_EO CN 2.641.488 2,538,878 102,610 102,610
1789 COM_EO SG 74.202.015 70.114.598 4.087.416 4.087,416
1790 COM_EO SE 114.538 107,256 7.282 7,282
1791 COM_EO SG 1.055,756 997,599 58.156 58.156
1792 COM_EO SG 1.590 1,503 88 88
1793 B8 242.335,471 229,504.341 12.831.130 12,831.130
1794
1795 398 Misc. Equipment
1796 G-SITUS S 1,354,746 1.290,393 64,352 64,352
1797 PT SG
1798 PT SG 1,997 1,887 110 110
1799 CUST CN 199,765 192.005 7,760 7.760
1800 PTD SO 3,376,792 3.194.641 182.151 182.151
1801 P SE 1,668 1.562 106 106
1802 G-G SG 1,865.540 1.762,777 102,763 102.763
1803 G-SG SG
1804 B8 6,80,507 6,443.265 357,242 357,242
1805
1806 399 Coal Mine
1807 p SE 278.021,722 260,346,431 17,675,291 13,146,472 30.821.763
1808 MP P SE
1809 B8 278.021.722 260,346,431 17,675,291 13.146,472 30,821,763
1810
1811 399L WIDCO Capital Lease
1812 p SE B8
1813
1814
1815 Remove Capil Leases
1816 B8
1817
ROLLED-IN Page 9.29
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1818 1011390 General Capital Leases
1819 G-SITUS S 18,984,156 18,984,156
1820 P SG 16,951,793 16,018,004 933,789 933,789
1821 PTD SO 12,664,054 11,980.930 68S,123 683,123
1822 B9 48.600,002 46,983,090 1,616,913 1,616,913
1823
1824 Remove Capital Leases (48,600,002)(46.983,090)(1,616,913)(1,616,913)
1825
1826
1827 1011346 General Gas Line Capital Leases
1828 P SG
1829 B9
1830
1831 Remove Capital Leases
1832
1833
1834 GP Unclassified Gen Plant - Acct 300
1835 G-SITUS S
1836 PTD SO 4,694,044 4,440,838 253.206 253,206
1837 CUST CN
1838 G-SG SG
1839 PT SG
1840 PT SG
1841 B8 4,694.044 4,440,838 253,206 253,206
1842
1843 399G Unclassified Gen Plant - Acet 300
1844 G-SITUS S
1845 PTO SO
1846 G-SG SG
1847 PT SG
1848 PT SG
1849 B8
1850
1851 Total General Plant B8 1,205,461,579 1,131,478,731 73,982,849 13,146,472 87,129,320
1852
1853 Summary of General Plant by Factor
1854 S 489,306,322 457,507,766 31,798,556 31.798,556
1855 OGP
1856 OGU
1857 SG 210,650,900 199,047,199 11,603,700 11,603,700
1858 SO 250,401.250 236,894,123 13,507,126 13,507,126
1859 SE 278,728,427 261,008.207 17,720,220 13,146,472 30,866.692
1860 CN 24,974,683 24,004,525 970,158 970,158
1861 OEU
1862 SSGCT
1863 SSGCH
1884 Less Capital Leases
áõ48,600.002)
(46,983.090)~1.616,913)(1,616.913)
1865 Total General Plant by Factor 1. 5,461.579 1.131.478.731 3.982,849 13.146,472 87.129,320
1866 301 Organization
1867 I-SITUS S
1868 PTO SO
1869 I-SG SG
1870 B8
1871 302 Franchise & Consent
1872 I-SITUS S 1.000.000 1,000.000 1,000,000
1873 I-SG SG 9,402,471 8.884,536 517,935 517,935
1874 I-SG SG 99,510,474 94,028.942 5,481,532 5.461,532
1875 I-SG SG 9,240,742 8,731,716 509.026 509,026
1876 P SG
1877 P SG 600,993 567,887 33,106 33,106
1878 B8 119,754.679 112,213.080 7.541,599 7.541.599
1879
ROLLED-IN Page 9.30
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1880 303 Miscellaneous Intangible Plant
1881 I-SITUS S 6,042,837 5,626,978 415,859 415,859
1882 I-SG SG 95,041,256 89,805,910 5,235.346 631,847 5,867,193
1883 PTO SO 366,513,585 346,743,135 19.770,450 19.770,450
1884 P SE 3,453,872 3,234,291 219,581 219,581
1885 CUST CN 118,758,961 114,145,691 4,613,271 4,613.271
1886 P SG
1887 P SG
1888 B8 589.810,510 559,556,004 30,254,506 631,847 30,886,353
1889 303 Less Non-Utilty Plant
1890 I-SITUS S
1891 589,810,510 559,556,004 30,254,506 631,847 30,886,353
1892 IP Unclassified Intangible Plant" Acct 300
1893 I-SITUS S
1894 I-SG SG
1895 P SG
1896 PTO SO
1897
1898
1899 Totl Intangible Plant B8 709.565,190 671,769,085 37,796,105 631,847 38,427,952
1900
1901 Summary of Intangible Plant by Factor
1902 S 7,042,837 5,626,978 1,415,859 1,415,859
1903 OGP
1904 DGU
1905 SG 213,795,935 202,018,990 11,776,945 631.847 12.408,792
1906 SO 366,513,585 346,743,135 19,770.450 19,770,450
1907 CN 118,758.961 114,145,691 4,613.271 4,613,271
1908 SSGCT
1909 SSGCH
1910 SE 3,453,872 3,234,291 219.581 219,581
1911 Total Intangible Plant by Factor 709.565,190 671,769,085 37,796,105 631,847 38,427,952
1912 Summary of Unclassified Plant (Account 106)
1913 OP 20.216,252 19,291,256 924.997 924,997
1914 OSO
1915 GP 4,694,044 4,440,838 253,206 253.206
1916 HP
191.NP
1918 OP
1919 TP 84,550,623 79,893,154 4,657,469 4,657,469
1920 TSO
1921 IP
1922 MP
1923 SP 787,304 743.936 43,369 43,369
1924 Total Unclassified Plant by Factor 110,248.224 104,369,183 5,879,040 5,879,040
1925
1926 Totl Electic Plant In service B8 19,556;037,605 18,501,147.212 1,054,890,394 112,270,443 1,167,160,837
ROLLED-IN Page 9.31
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1927 Summary of Electric Plant by Factor
1928 S 5.822.986.950 5.524.998.077 297.988.873 297,988.873
1929 SE 282,182.299 264.242;498 17,939,801 13.146.472 31,086,273
1930 DGU
1931 DGP
1932 SG 12.738.819.880 12.037,102.253 701.717.627 99.123.971 800,841.599
1933 SO 616,914.834 583.637.258 33,277.576 33.277.576
1934 CN 143.733.644 138.150.216 5.583;429 5.583;429
1935 DEU
1936 SSGCH
1937 SSGCT
1938 Less Capital Leases (48,600,002)(46,983,090)(1.616,913)(1.616.913)
1939 19,556.037.65 18.501,147,212 1.054.890.394 112,270.443 1.167.160,837
1940 105 Plant Held For Future Use
1941 DPW S 3;473.204 3;473,204
1942 P SNPPS
1943 T SNPT 325.029 307,125 17.904 (509.44)(491.540)
1944 P SNPP 8.923.302 8;431,762 491.540 491.540
1945 P SE 953,014 892,426 60.588 (60.588)
1946 G SNPG
1947
1948
.1949 Total Plant Held For Future Use B10 13,674,549 13,104,516 570,032 (570,032)0
1950
1951 114 Electric Plant Acquisition Adjustments
1952 P S
1953 P SG 142.633.069 134,776,129 7.856.940 7.856.940
1954 P SG 14.560.711 13.758,634 802.076 802.076
1955 Total Electric Plant Acquisition Adjustment B15 15,193,780 148,53,764 8,659,016 8,659,016
1956
1957 115 Accum Provision for Asset Acquisiton Adjustments
1958 P S
1959 P SG (84.100.707)(4,632.686)
1960 P SG (12,226.166)673,478)
1961 815 , 73
1962
1963 120 Nuclear Fuel
1964 P SE
1965 Total Nuclear Fuel B15
1966
1967 124 Weatherization
1968 DMSC 5 2.633.178 2.599.959 33,220 33,220
1969 DM5C 50 (4;454)(4,213)(240)(240)
1970 816 2,628,725 2.595.745 32,979 3i979
1971
1972 182W Weatherization
1973 DMSC S 34.729,463 31,258.802 3;470,661 3;470,661
1974 DMSC 5G
1975 DMSC SG
1976 DMSC SO
1977 816 34,729,463 31258,802 3.70.661 3,470.661
1978
1979 186W Weatherization
1980 DMSC S
1981 DMSC CN
1982 DMSC CNP
1983 DMSC SG
1984 DMSC SO
1985 816
1986
1987 Total Weatheriation B16 37,358,188 33,854,54 3,503,64 3,503,64
ROLLED-IN Page 9.32
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
1988
1989 151 Fuel Stock
1990 P DEU
1991 P SE 158.860.196 148,760.625 10,099.571 1,566.785 11,666,357
1992 P SE
1993 P SE 12.069,947 11.302,597 767.349 767,349
1994 Total Fuel Stock B13 170,930,143 160,063,222 10,866,921 1,566,785 12,433,706
1995
1996 152 Fuel Stock - Undistributed
1997 P SE
1998
1999
2000 25316 DG& T Working Capital Deposit
2001 P SE (1,379,000)(1.291.330)(87,670)(56.073)(143,744)
2002 813 (1.379,000)(1,291,330)(87,670)(56,073)(143,744)
2003
2004 25317 DG&T Working Capital Deposit
2005 P SE (1.758.544)(1,646,744)(111,800)(5,907)(117,706)
2006 813 (1,758.544)(1,646.744)(111,800)(5,907)(117.706)
2007
2008 25319 Provo Working Capital Deposit
2009 P SE
2010
2011
2012 Total Fuel Stock 813 167.792,599 157,125,148 10,667,451 1.504,805 12.172,256
2013 154 Matenals and Suppiies
2014 MSS S 86,919,683 82.030,372 4,889,311 4,889,311
2015 MSS SG 3,082,186 2.912,404 169,782 169,782
2016 MSS SE 4,170.119 3,905,003 265,116 265.116
2017 MSS SO 253.641 239.959 13,682 13,682
2018 MSS SNPPS 81,516.215 77,025,896 4,490,319 4,490,319
2019 MSS SNPPH (1,860)(1,757)(102)(102)
2020 MSS SNPD (3,081,941)(2,939,745)(142.196)(142.196)
2021 MSS SNPT
2022 MSS SG
2023 MSS SG
2024 MSS SNPPS
2025 MSS SNPPO 5,288.978 4,997,635 291,343 291,343
2026 MSS SNPPS
2027 Total Materials and Supplies B13 178,147,022 168,169,767 9,977,255 9,977,255
2028
2029 163 Slores Expense Undistnbuted
2030 MSS SO
2031
2032 813
2033
2034 25318 Provo Working Capital Deposit
2035 MSS SNPPS (273.000)(257,962)(15,038)(15.038)
2036
2037 813 (273,000)(257.962)(15.038)(15.038)
2038
2039 Total Matenals & Suppiies 813 177,874.022 167.911,805 9,962.217 9.962.217
2040
2041 165 Prepayments
2042 DMSC S 2,934,455 2.770,438 164,017 164.017
2043 GP GPS 9.858,973 9,327.161 531,812 531.812
2044 PT SG 6,415,547 6,062.148 353,400 353,400
2045 P SE 7,102,118 6,650.600 451,519 451,519
2046 PTD SO 19.839,360 18,769,187 1,070,173 1.070.173
2047 Total Prepayment B15 46,150,45 43,579,532 2,570,921 2,570,921
2048
ROLLED-IN Page 9.33
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2049 182M Mise Regulatory Assets
2050 DDS2 S 56,142,627 56,331,298 (188,671)(17.580)(206,251)
2051 DEFSG SG 2,654.642 2.508,411 146.231 74.43 220.665
2052 P SGCT 8,511,723 8.041.060 470.663 470,663
2053 DEFSG SG
2054 P SE 74.327 74.327
2055 P SG
2056 DDS02 SO 7.516.382 7.110.934 405,448 405,448
2057 B11 74.825.374 73,991.703 833.671 131.81 964.852
2058
2059 186M Mise Deferred Debits
2060 LABOR S 16.240,410 16.240,410
2061 P SG
2062 P SG
2063 DEFSG SG 38.988.960 36.841.254 2,147.706 531.032 2.678.738
2064 LABOR SO 16.926 16,013 913 913
2065 P SE 10,045.914 9,407.242 638.671 (108.911 )529.760
2066 P SNPPS
2067 GP EXCTAX
2068 Total Misc. Deferred Debits B11 65,292,210 62,50,920 2,787,290 422,121 3,209,411
2069
2070 Working Capital
2071 CWC Cash Working Capital
2072 CWC S 36.107.073 34,139.976 1.967.097 (25.961)1.941,136
2073 CWC SO
2074 CWC SE
2075 B14 36.107.073 34,139.976 1,967.097 (25.961)1.941.136
2076
2077 OWC Otr Work. Cap.
2078 131 cah GP SNP
2079 135 Working Fund GP SG 1.920 1.814 106 106
2080 141 Note Reeabl GP SO 540.572 511,412 29.159 29.159
2081 143 Other AIR GP SO 33.985.372 32.152.136 1.833.237 1.833.237
2082 232 Al PTD S
2083 232 Al PTD SO (4;215,163)(3;987.789)(227.374)(227.374)
2084 232 Al P SE (1,408,497)(1.318.951)(89.545)(89.545)
2085 232 Al T SG
2086 2533 Othe Msc_ Of. Crd. P S
2087 2533 Ot"' Ms. 01. Crd. P SE (6.046.034)(5.661,656)(384.378)(384.378)
2088 230 Ast Ref. Oblig. P SE (2,415.872)(2.262,283)(153.590)(153.590)
2089 230 Ast ReU. Oblig. P S
2090 254105 ARO Re U..hlty P S
2091 254105 ARO Re LJability P SE (716.594)(671.036)(45.558)(45.558)
2092 2533 ChOa Reclametlon P SE
2093 B14 19.725.703 18,763.64 962.057 962.057
2094
2095 Total Working Capital B14 55,832,776 52,903,622 2,929,154 (25,961)2,903,193
2096 Miscellaneous Rate Base
2097 18221 Unree Plant & Reg Study Costs
2098 P S
2099
2100 B15
2101
2102 18222 Nuclear Plant - Trojan
2103 P S (372.363)(372.363)
2104 P TROJP 885.265 835.358 49.907 49,907
2105 P TROJD 1.296.271 1.222.899 73.372 73.372
2106 B15 1.809.172 1.685.894 123.279 123.279
2107
2108
ROLLED-IN Page 9.34
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2109
2110 1869 Misc Deferred Debits-Trojan
2111 P S
2112 P SNPPN
2113 B15
2114
2115 Total Miscellaneous Rate Base B15 1,809,172 1,685,894 123,279 123,279
2116
2117 Total Rate Base Additions B15 701,476,249 664,175,741 37,300,508 1,462,114 38,762,622
2118 235 Customer Service Deposits
2119 CUST S
2120 CUST CN
2121 Total Customer Service Depoits B15
2122
2123 2281 Prop Ins PTD SO
2124 2282 Inj& Dam PTD SO (7,487,871)(7,083,961)(403.910)(403,910)
2125 2283 Pen & Ben PTD SO (22,725,860)(21,499,983)(1,225,877)(1,225,877)
2126 254 Reg Liab PTD SG
2127 254 Reg L1ab PTD SE (1,217,286)(1,139.897)(77,389)77,389
2128 254 Ins Prov PTD SO (109,564)(103,54)(5.9101 (5,910)
2129 B15 (31,540.581 )(29.27,495)(1,713,086 77,389 (1,635,697)
2130
2131 22841 Accum Misc Oper Provisions - Other
2132 P S
2133 P SG (1,417,373 (82,627
2134 B15 ,41 ,373 7)
2135
2136 22842 Prv-Trojan P TROJD
2137 230 ARO P TROJP (1,711,281)(1,614,808)(96,473)(96,473)
2138 254105 ARO P TROJP (3,608,947)(3,405,494)(203,53)(203,453)
2139 254 P S
f6,009,324)(6,009,324)
2140 .B15 (1,329,552)(11,029,626)(299,926)(299,926)
2141
2142 252 Customer Advances for Constrction
2143 DPW S (13,473.111)(13,198,024)(275,088)6,822 (268,266)
2144 DPW SE
2145 T SG (7,471,547)(7,059,977)(411,570)(267,861)(679,431)
2146 DPW SO
2147 CUST CN
2148 Total Customer Advances for Construction B19 (20,94,658)(20,258,001)(686,658)(261,039)(94,697)
2149
2150 25398 S02 Emissions
2151 P SE
12.1°o.793l 12,100,793)2152 B19 2,100,793 2,100,793)
2153
2154 25399 Other Deferred Credits
2155 P S (3.803.740)(3,728,560)(75,180)(75,180)
2156 LABOR SO (181,348)(181,348)
2157 P SG (8,008,237)(7,567,103)(441,134)(441,134)
2158 P SE (1,183,310)r,108,081l (75,229)(75,229)
2159 B19 (12,995,286)( 2,403,743 (591,543)(181,348)(77,891)
ROLLED-IN Page 9.35
Year-End
FERC BUS UNADJUSTED RE5UL T5 IDAHO
ACCT DE5CRlP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2160
2161 190 Accumulated Deferred Income Taxes
2162 P 5 10,695,484 10,695,48 (2)(2)
2163 CU5T CN 65,488 62,944 2,544 2,544
2164 P IBT
2165 LABOR SO 36,490,690 34,522,312 1.968,378 (49,979)1,918,399
2166 P DGP
2167 CU5T BADDEBT 3,345,135 3.215,387 129,748 129,748
2168 P TROJD 1,332,481 1,257.059 75,422 75,422
2169 P 5G 39,391,566 37,221.682 2,169,884 (2,002.880)167.004
2170 P 5E 3,097,022 2,900,128 196,894 (461,730)(264.837)
2171 PTD 5NP
2172 DPW 5NPD 703,493 671.035 32,458 32,458
2173 P 55GCT
2174 Total Accum Deferred Income Taxes 819 95,121,359 90,54,034 4,575,325 (2,514,589)2,060,736
2175
2176 281 Accumulated Deferred Income Taxes
2177 P 5
2178 PT DGP
2179 T 5NPT
2180 B19
2181
2182 282 Accumulated Deferred Income Taxes
2183 GP 5 (138,317 ,516)(138,317,516)
2184 ACCMDIT DITBAL (2,336,392,077)(2,195,736,556)(140,655,521 )140,655,521 0
2185 P 5G
2186 LABOR SO (6,909,549)(6,536,835)(372,714)6,816 (365,899)
2187 CU5T CN
2188 P 5E (5,607,614)(5.251,109)(356,505)(234,572)(591,Q8)
2189 P 5G (5.705,530)(5,391,241)(314,289)(16,482,797)(16,797,086)
2190 B19 (2,354,614.770)(2.212.915,740)(141,699,030)(14,372,54)(156,071,578)
2191
2192 283 Accumulated Deferred Income Taxes
2193 GP S (30,884,504)(29,777,409)(1,107,095)1,028,227 (78,868)
2194 P 5G (6,716,785)(6,346.791)(369,994)(41,055)(411,048)
2195 P SE (4,844,933)(4,536,915)(308,018)41,333 (266,685)
2196 LABOR SO (16.761,723)(15,857,563)(904,160)710,964 (193,195)
2197 GP GP5 (5,687,055)(5.380,284)(306,771)(306,771)
2198 PTD 5NP (5,228,914)(4,951,159)(277,755)(277,755)
2199 P TROJD
2200 P 5G
2201 P 5G (2,701,338)(2,552.535)(148.803)(148,803)
2202 P 5G
2203 B19 (72,825,252)(69,402.657)(3,422,595)1,739,470 (1,683,125)
2204
2205 Total Accum Deferrd Income Tax 819 (2,332,318,663)(2,191,772,364)(140,54,299)(15,147,668)(155,693,967)
2206 255 Accumulated Investment Tax Credit
2207 PTD S
2208 PTD ITC84 (1,745,297)(1,745,297)
2209 PTD ITC85 (3.04.242)(3,044,242)
2210 PTD ITC86 (1,479,759)(1,479,759)
2211 PTD ITC88 (222,246)(222,246)
2212 PTD ITC89 (486,772)(486,772)
2213 PTD ITC90 (315,906)(271,738)(44,168)(44,168)
2214 PTD IBT -(166,992l
1166,992)2215 Totl Accumlated ITC 619 (7,294,222)(7.250,04)(44,168)(166,992 211,161)
2216
2217 Total Rate Elase Deductions (2,417,922,963)(2,273,958,655)(143,96,308)(17,780,451)(161,744,759)
2218
ROLLED.IN Page 9.36
Year.End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2219
2220
2221 108SP Steam Prod Plant Accumulated Depr
2222 P S
2223 P SG (828,531,539)(782,891,896)(45,639,643)(45,639,643)
2224 P SG (936,120,976)(884,554,772)(51.566,204)(51,566.204)
2225 P SG (552,789,110)(522,338.733)(30,450,377)(761,613)(31,211,990)
2226 P SG (158,685,661)(149,944,465)(8,741,196)(8,741,196)
2227 617 (2,476,127,286)(2,339,729,866)(136.397,420)(761,613)(137,159,033)
2228
2229 108NP Nuclear Prod Plant Accumulated Depr
2230 P SG
2231 P SG
2232 P SG
2233 617
2234
2235
2236 108HP Hydraulic Prod Plant Accum Depr
2237 P S
2238 P SG (150,429,735)(142,143,316)(8,286,419)(8.286 ,419)
2239 P SG (28,604,226)(27,028,563)(1,575,663)(1,575.663)
2240 P SG (59,853.861)(56,556,813)(3,297,049)(143,255)(3,440,304)
2241 P SG (12,861,842)(12,153,348)(708,494)(708,494)
2242 617 (251,749.664)(237.882,039)(13,867.625)(143,255)(14,010,880)
2243
2244 1080P Other Production Plant - Accum Depr
2245 P S
2246 P SG (1,347,482)(1,273.256)(74,226)(74.226)
2247 P SG
2248 P SG (263,762,956)(249,233,579)(14,529,377 (565,003)(15,094,380)
2249 P SG (19.564.578)(18,86,863)(1,077,714)(1.077,714)
2250 617 (284,675.015)(268,993,698)(15,681,317)(565.003)(16.246,321 )
2251
2252 108EP Experimental Plant. Accum Depr
2253 P SG
2254 P SG
2255
2256
2257 Total Product Pla Accum Depreciation B17 (3,012,551,966)(2,846,605,604)( 165,946,362)(1,469,872)(167,416,234)
2258
2259 Summary of Prod Plant Depreciation by Factor
2260 S
2261 DGP
2262 DGU
2263 SG (3,012,551,96)(2,846,605,604)(165,946,362)(1,469.872)(167,416,234)
2264 SSGCH
2265 SSGCT
2266 Total of Prod Plant Depreciation by Factor (3,012,551,966)(2.846,605.64)(165,94,362)(1,469,82)(167,416,234)
2267
2268
2269 108TP Transmission Plant Accumulated Depr
2270 T SG (21,367,434)
2271 T SG (21,35,659)
2272 T SG 20,231,189)(1.032,549)
2273 Total Trans Plant Accum Depreciation 617 ,9 ,,2,9
ROLLED-IN Page 9.37
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2274 108360 Land and Land Rights
2275 DPW S (5.731.126)(5,71.879)(259.247)(259.247)
2276 817 (5.731.126)(5,71.879)(259.247)(259.247)
2277
2278 108361 Structures and Improvements
2279 DPW S (13.581.278)(13.138.403)(442.875)(442.875)
2280 817 (13.581.278)(13.138.403)(442.875)(442.875)
2281
2282 108362 Station Equipment
2283 DPW S (207.834.133)(198.557.095)(9.277.038)(9.277038)
2284 617 (207.834.133)(198.557.095)(9.277.038)(9.277.038)
2285
2286 108363 Storage 8attery Equipment
2287 DPW S (775.263)(775.263)
2288 817 (775.263)(775.263)
2289
2290 108364 Poles. Towers & Fixtures
2291 DPW S (472,497.456)(438.618,89)(33.878.967)(33.878.967)
2292 817 (472,497,456)(438.618,89)(33.878.967)(33.878,967)
2293
2294 108365 Overhead Conductors
2295 DPW S (257.576.586)(247.145.604)(10,430.983)(10.430.983)
2296 617 (257.576.586)(247.145.604)(10,430.983)(10,430.983)
2297
2298 108366 Underground Conduit
2299 DPW S (121,003.027)(117.701.126)(3.301.901 )(3.301.901 )
2300.617 (121.003.027)(117.701.126)(3.301.901 )(3.301.901 )
2301
2302 108367 Underground Conductors
2303 DPW S (279.736.871)(268.973.545)(10.763.326)(10.763.326)
2304 817 (279.736.871)(268.973.545)(10.763.326)(10.763.326)
2305
2306 108368 Line Transformers
2307 DPW S (361.323.647)(337.660.494)(23.663,153)(23.663,153)
2308 617 (361,323.647)(337.660,494)(23.663,153)(23.663,153)
2309
2310 108369 5ervices
2311 DPW 5 (163,299,910)(152.868.799)(10.31.110)(10.431,110)
2312 817 (163.299.910)(152.868.799)(10,431,110)(10.431.110)
2313
2314 108370 Meters
2315 DPW S (84.175.634)(75.808.861 )(8.366.773)(8,366.773)
2316 617 (84.175.634)(75,808.861 )(8.36.773)(8.366.773)
2317
2318
2319
2320 108371 Installations on Customers' Premises
2321 DPW 5 (7.846.403)(7.709,414)(136,989)(136,989)
2322 617 (7,846.403)(7.709,414)(136,989)(136.989)
2323
2324 108372 Leased Propert
2325 DPW 5
2326 617
2327
2328 108373 Street Lights
2329 DPW 5 (28.660,733)(28.170.544)(490,188)(490.188)
2330 617 (28.660.733)(28.170.544)(490.188)(490.188)
2331
2332 108000 Unclassified Dist Plant - Acc 300
2333 DPW S
2334 817
2335
2336 10805 Unclassied Dist Sub Plant - Acct 300
2337 DPW S
233 817
2339
234 108DP Unessifi Dit Sub Plant - Acct 300
231 DPW S 730,582 729.334 1.248 1.248
2342 617 730.582 729.334 1,248 1,248
234
234
234 Totl Dlstrbulon Plant Accum Depreiaton B17 (2,003,311,485)(1,891,870,183)(111,441,302)(111,441,302)
234
2347 Summary of Distrbuion Plant Depr by Factor23S (2,003,311.485)(1,891.870.183)(111.441.302)(111,441,302)
2349
2350 Total Distributi Depriatin by Factor 617 (2.003,311.48)(1.891870,183)(111.441,302)(11.441,302)
ROLLED-IN Page 9.38
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2351 108GP General Plant Accumulated Oepr
2352 G-5ITU5 5 (151.989,352)(141,794.438)(10.194,914)(10.194,914)
2353 PT 5G (6,272,465)(5,926,947)(345,519)(345,519)
2354 PT 5G (11,172,030)(10,556,619)(615,11)(615.411)
2355 G-SG SG (46.253.779)(43.705,891 )(2.547.888)(2,547.888)
2356 CU5T CN (6.625.150)(6.367,792)(257.358)(257.358)
2357 PTD SO (72.527.529)(68,615,254)(3.912.275)(3.912.275)
2358 P 5E (339.900)(318.291)(21.609)(21.609)
2359 G-5G SG (33,094)(31.271)(1.823)(1.823)
2360 G-SG 5G (2.331.547)(2.203.113)(128,433)(128.433)
2361 B17 (297.544,84)(279,519.616)(18.025.230)(18.025.230)
2362
2363
2364 108MP Mining Plant Accumulated Depr.
2365 P 5
2366 P 5E (170,270.750)(159,445.750)(10.825,000)(41.661)(10,866.661)
2367 B17 (170,270,750)(159,445.750)(10,825,000)(41.661)(10,866,661 )
2368 108MP Less Centralia Situs Depreciation
2369 P 5
2370 B17 (170,270,750)(159.445.750)(10,825.000)(41.661)(10.866.661)
2371
2372 1081390 Accum Oepr - Capital Lease
2373 PTO 50 B17
2374
2375
2376 Remove Capital Leases
2377 B17
2378
2379 1081399 Accum Depr - Capital Lease
2380 P 5
2381 P 5E 817
2382
2383
2384 Remove Capital Leases
2385 B17
2386
2387
2388 Total General Plant Accum Depreciation 817 (467,815,596)(438,965,366)(28,850,230)(41,661)(28.891,891 )
2389
2390
2391
2392 5ummary of General Depreciation by Factor
2393 5 (151.989.352)(141.794,438)(10,194,914)(10.194.914)
2394 DGP
2395 DGU
2396 5E (170.610.651)(159.764.042)(10,846,09)(41.661)(10,888.270)
2397 50 (72.527.529)(68.615.254)(3,912.275)(3,912.275)
2398 CN (6.625.150)(6,367.792)(257.358)(257,358)
2399 SG (66,062.915)(62,423,841)(3.639.074)(3.639,074)
2400 DEU
2401 5SGCT
2402 55GCH
2403 Remove Capital Leases -
2404 Total General Depreciallon by Factor (467.815.596)(438.965.366)(28.850.230)(41.661)(28,891.891 )
2405
2406
2407 Totl Accum Depreciaton - Plant In Servce B17 (6,626,518,392)(6,257.327,216)(369,191,176)(2,54,082)(371,735,257)
2408 111SP Accum Prev for Amort-5team
2409 P SG
2410 P SG
2411 B18
2412
2413
2414 111GP Accum Prev for Amort-General
2415 G-SITUS 5 (15.417.186)(15,417.186)
2416 CUST CN (2.453,306)(2,358,005)(95,300)(95,300)
2417 I-5G 5G
2418 pro 50 (9.907.217)(9.372,803)(534,414)(534,414)
2419 P SE
2420 B18 (27,777,708)(27 '1f ,994)(629,715)(629.715)
2421
ROLLED-IN Page 9.39
Year-End
FERC BUS UNADJUSTED RESULTS IDAHO
ACCT DESCRIP FUNC FACTOR Ref TOTAL OTHER IDAHO ADJUSTMENT ADJTOTAL
2422
2423 111HP Accum Prov for Amort-Hydro
2424 P SG
2425 P SG
2426 P SG (13,027)(12,310)(718)(718)
2427 P SG (390,637)(369,119)(21,518)(21,518)
2428 618 (403,664)(381,429)(22,236)(22,236)
2429
2430
2431 1111P Accum Prov for Amort-Intangible Plant
2432 I-SITUS S (866.992)(130,826)(736,166)(736,166)
2433 P SG
2434 P SG (332,638)(314,315)(18.323)(18,323)
2435 P SE (1,011,087)(946,807)(64,280)(64,280)
2436 I-SG SG (42,153,361)(39,831,344)(2,322,017)(25,402)(2,347,419)
2437 I-5G SG ( 11,454,352)(10,823,389)(630,963)(630,963)
2438 I-SG SG (3,111,807)(2,940,393)(171,414)(171,414)
2439 CUST CN (89,511,348)(86,034,220)(3,477,128)(3,477,128)
2440 P SG
2441 P SG (67,877)(64,138)(3.739)(3,739)
2442 PTD SO (250,449,855)(236,940,106)(13,509,748)(13,509,748)
2443 618 (398,959.316)(378,025,538)(20,933,778)(25,402)(20.959,180)
2444 1111P Less Non-Utiity Plant
2445 NUTIL OTH
2446 (398,959,316)(378,025,538)(20,933,778)(25,42)(20.959.180)
2447244 111390 Accum Amtr - Capital Lease
2449 G-SITUS S (5.302,423)(5,302,423)
2450 P SG (1,390.857)(1.314,242)(76.615)(76,615)
2451 PTD SO 1.860.994 1,760,608 100.386 100,386
2452 (4.832.287)(4.856,057)23.770 23,770
2453
2454 Remve Capitl Leae Amtr 4.832.287 4,856.057 (23,770)(23,770)
2455
2456 Total Accum Provision fOr Amortizaion B18 (427.140,689)(405,55,960)(21,585,729)(25,402)(21,611 131)
2457
2458
2459
2460
2461 Summary of Amortization by Factor
2462 S (21,586,00)(20,850,434)(736.166)(736,166)
2463 DGP
2464 DGU
2465 SE (1,011,087)(946,807)(64.280)(64.280)
2466 SO (258,496,078)(244,552,301 )(13,943,777)(13.943.777)
2467 CN (91,964,653)(88,392,225)(3.572,428)(3.572,428)
2468 SSGCT
2469 SSGCH
2470 SG (58.914,556)(55.669.249)(3.245,307)(25,402)(3,270,709)
2471 Less Capitl Lease 4,832,287 4,856,057 (23,770)(23,770)
2472 Total Provision For Amortzation by Factor (427.140,689)(405,554,96)(21,585.729)(25.402)(21.611,131)
Idaho General Rate Case - Rebuttal
Factors December, 2010
Year End Factors
Page 10.1
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DECEMBER 2010 FACTORS
Idaho General Rate Case. December 2009
COINCIDENTAL PEAKS
I
Month Day TIme
Jan.10 25 19
Feb.10 4 8
Mar.10 30 8
Apr.10 1 8
May.10 18 15
Jun.10 24 15
Jul.10 19 16
AU9.1O 26 15
Sep.10 9 15
Oct.10 4 19
Nov.10 24 18
Dec.10 15 18
Month
Jan.10
Feb.10
Mar.10
Apr.10
May.10
Jun-10
Jul-10
Aug-10
Sep10
Oc-10
Nov-10
Dec.10
Month
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Feb.10
Mar-10
Apr.10
May.10
Jun.10
Jul-10
Aug-10
Sep-10
Oct-10
Nov-10
Dec-10
Month
Jan-10
Feb.10
Mar.10
Apr-10
May-10
Jun-l0
Jul.10
Au10
Sep10
Oc.10
Nov-10
Dec-l0
Moth
Jan-10
Feb10
Ma.10
Apr.10
May-10Ju10Jul0
Au.10Sep10
Oc.10
No..10De10
Day
25
4
30
1
18
24
19
26
9
4
24
15
Day
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1
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19
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g
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19
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g
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30
1
18
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19
26
9
4
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15
TIme
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8
8
8
15
15
16
15
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19
18
18
I r.EREPLOAS ICP)
I "'øíER FERC
CA OR WA E.WY Total UT ID W.WY UT Total
158 2,667 722 g75 3,37 406 237 28 8,602
153 2,528 751 1,018 3,144 416 211 27 8,221
145 2,315 669 983 2,914 399 237 16 7,661
131 2,132 585 966 2,819 415 210 30 7,257
142 1,816 636 934 3,590 503 228 24 7,848
148 1.96 678 1,003 4,197 613 218 43 8,821
153 2,257 750 1,019 4,525 684 228 39 9,595
150 2,301 727 1,008 4,445 538 226 44 9,395
134 2,068 652 946 4,084 447 223 34 8,553
121 1,964 610 949 3,048 406 238 23 7,336
139 2,231 696 1,031 3,515 443 266 29 8,322
157 2,408 736 1,067 3,709 467 252 35 8,796
1,729 26,650 8,212 11,899 43,426 5.718 2,774 372 100,407
(less)
Adjustments for Curtilments, Buy.Throuhs and Load No Lon_ Served IReductons to Loadl... . Cc NøtH::I:.RC.:iRCS :iCA OR WA E. WY UT ID W. W UT Total(88) (88)
(231)
(228)
(237)
(197)
(184)
(189)
(182)
(415)
(417)
(420)
(197)
(74)
1,055
(74)
1,6101
=555
equals
TIme
19
8
8
8
15
15
16
15
15
19
18
18
I COlN'CIDENiAl PEAK~RVD FROM COMPANY Rl:SOURCE$ I
i NonRC FERC
CA OR WA E.WY UT ID W,W'UT Total
158 2,667 722 975 3,349 406 237 28 8.514
153 2,528 751 1,018 3,144 416 211 27 8,221
145 2.315 669 983 2,914 399 237 16 7,661
131 2,132 585 966 2,819 415 210 30 7,257
142 1,816 636 934 3,90 503 228 24 7,848
148 1,984 678 1,003 3,966 429 218 43 8.07
153 2,257 750 1.019 4,297 475 228 39 9,178
150 2,301 727 1,008 4,208 356 226 44 8,975
134 2,068 652 946 3,866 447 223 34 6,356
121 1,964 610 949 3,04 406 238 23 7.336
139 2.231 696 1,031 3,515 443 266 29 8,322
157 2,408 736 1,067 3,635 467 252 35 8,722
1,729 26,650 8,212 11,899 42,370 5,163 2,774 372 98,797
+ plus
Adjustmen
TIme
19
8
8
8
15
15
16
15
15
19
18
18
Isfor Arar SeIces Contr Includng Reseres IAdltions to Load!and normalltonofIrrgation andMon
I :;g;~;~)li~~O!fl_~~ih¿:,~i':r\J,L~j~if;D:;~~1:¡~£§r~~~:~0Jt_¡0~..:l~f!;i~~e~e\~C,¡¡¡¡¡¡El~¡.~~;?~Jtt't~;;:¡it0l\tIWI
CA OR WA E.WY VT ID W.WY UT Total
-
-
-
-
-
-
.
-.-.-.-.--equals
TIme
19
8
8
8
15
15
16
15
15
19
18
18
I LOADS FOR JURlS0CTlAL ALLOCATIOt tc:p)-I__c ..ÆRC
CA OR WA E,WY UT 10 W.WY UT Total
158 2.667 722 975 3.349 406 237 28 8.514
153 2,528 751 1,018 3.144 416 211 27 8,221
145 2,315 669 983 2.914 399 237 16 7.661
131 2,132 585 966 2.819 415 210 30 7.257
142 1,816 636 934 3,590 503 228 24 7,84
148 1.984 678 1.003 3.96 429 218 43 8,407
153 2,257 750 1.019 4,297 475 228 39 9,178
150 2,31 727 1,008 4,208 358 226 44 8,975
134 2,06 652 946 3.886 447 223 34 8.35
121 1.96 610 949 3.04 406 238 23 7.336
139 2,231 696 1,031 3.515 443 266 29 8,322
157 2.408 736 1.067 3.635 467 252 35 8,722
1,72 26650 8,212 11,899 42.370 5,163 2,774 372 98,797
Page 10.13
ALOCTIOS USINPROF LOA
DECEMBER 2010 FACTORS
Idaho General Rate Cas . December 2009
ENERGY
Year Month2010 Jan2010 Feb2010 Mar2010 Apr
2010 May
2010 Jun2010 Jul2010 Aug2010 Sep2010 Oct2010 Nov2010 Dec
Year
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
2010
Year Month2010 Jan2010 Feb2010 Mar
2010 Apr2010 May
2010 Jun2010 Jul2010 AU9
2010 Sep2010 OCt
2010 Nov2010 Dec
1 METEDL .
.FERC
CA UK WA E.W'r Total UT lu W.vvY ui Total
83.440 1.317.180 417,820 685.090 2.091.64 293.020 168.500 20.034 5.05.694
70.500 1.176.930 359.160 630.56 1.85.104 245.88 137.35 16.674 4.472.484
73.320 1,224.960 362.450 678.000 1.887,261 268.860 172.790 17,901 4,667.641
71.750 1,103.860 331.570 827.440 1,788.547 262.230 145.690 17,807 4.331.087
77,430 1.105.020 337.770 670.110 1,932.851 314.58 170,770 17,151 4.608.531
80.930 1.076,430 33.250 622,640 2.036.210 359,88 154,08 19,900 4.663.420
87.820 1.205,590 364.810 669.960 2.397.004 414,870 164.66 23,944 5.324.714
83.470 1.191.060 367.570 671,940 2,34.784 371.140 164.410 23.864 5.214.374
72.540 1.078.670 352.770 637.150 2.003.824 291.080 158,380 18.36 4.594.414
68.570 1,109.380 367.210 678.810 1.891.210 267.470 172.480 17.490 4.555,130
71.390 1.187.280 378.410 687.510 2.049.882 261.240 179.260 16.242 4,814,972
82,270 1.357,880 427.930 708,350 2.120.465 277,880 173.120 18.775 5.147.895
923.430 14,134.240 4.440.720 7.967.580 24.395,787 3.628,130 1.961.490 228.14 57,451.367
Month
Jan
Feb
Mar
Ap
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
(less)
Adjustments for Curtilments. Buy Throahs and Load No Longer Servd (RedU~ctOnS to Loa."'''',OR WA E. WY UT D W
(6,124)
'CC
U Total
(6,124)
(4,281)
(5.815)
(5.736)
(3.640)
(4.792)
30;"\l17
CA
(4.281)
(5.815)
(5.736)
(3,640)
(4,792)
30.387
equals
I LOADS SERVED FROM COMPANY iuSOURCES INPC)
i Non-FCRC
CA OR WA E.WY UT 10 W. vv'uT Total
83.440 1.317.180 417,820 685,090 2,085.521 293.020 168,50 20.034 5.05.571
70.500 1.176.930 369.160 630,580 1.85.104 245.88 137.350 16.674 4.472.464
73,320 1.224.960 382.450 678.00 1.887.281 268.66 172,790 17.901 4.667.641
71,750 1,103.860 331.570 827,440 1,788,547 262,230 145,690 17.807 4.331.087
77.430 1.105,020 337,770 670.110 1.932,851 314,680 170,770 17,151 4.608.531
80.930 1.076.430 33.250 622.640 2.031.929 359,880 154.080 19.90 4.659;139
87.820 1.205.590 38.810 669,960 2.391.190 414,870 164.660 23.94 5.318.90
83.470 1.191.060 387.570 671,940 2.339.049 371,140 164.410 23,864 5.208.639
72.540 1.078.670 352.770 637,150 2.000.185 291.080 158.38 18.364 4.590.775
68.570 1.109.380 367.210 678.810 1.691,210 267.470 172,480 17.490 4.555.130
71.390 1.187.280 378,410 667.510 2.049.882 261.240 179.260 16.242 4.814.972
82.270 1.357.880 427.930 708.350 2,115.672 277.860 173.120 18.775 5.143.102
923,30 14.134.240 4.440.72l 7.7.56 24;AAl;;3g!'3.628.130 1.961.490 57.420.969
+ plus
Adustnts fo Ancilary Servce Contrct Includn9 Reservs IAiidltons to Load) and normalizion of Irron and Monanto,LY".EI.
Year Month CA UK WA E.WY Ui
2010 Jan 523
2010 Feb 467
2010 Mar 383
2010 Apr 371
2010 May 394
2010 Jun 500
201Q Jul 354
2010 Aug 435
2010 Sap 271
2010 Oct 36
2010 Nov 217
2010 De 303
4.60--
10
646
515
295
365
389
1.567
5.484
5.519
1,507
1.685
3,482
2,782
4.
W.Total
1.166
1.002
677
756
783
2.067
5.837
5.954
1.777
2.051
3.6993.0821f
Year Moth2010 Jan2010 Feb2010 Mar2010 Apr2010 May2010 Jun2010 Jul2010 Au92010 Sep2010 OC2010 No2010 De
equals
I LOADfORJ~SDCTJON ALLOCATJO!'. MW 1
I Jln-C'.FERC 'I
CA OR WA E. VV'UT lu W. vv in otl
83.44 1.317.180 417.820 685,090 2.088.043 293.66 168.50 20.034 5.051.739
70.50 1.176.930 358,160 630,56 1.85.5 246.395 137.35 16.674 4,473,488
73.32 1.224.960 362,450 678.00 1,887.643 269.155 172.790 17.901 4.688.318
71.750 1.103.880 331.570 627.440 1.788.919 262.615 145.690 17.607 4.331.844
77.43 1,105.020 337.770 670.110 1.93.245 314.969 170,770 17.151 4.609.314
80.930 1.076.43 33,250 622,840 2,03.429 361.447 154.080 19.90 4.661.206
87,820 1.205.59 38.810 669.960 2.391.543 420.354 164.880 23.944 5.324.737
83,470 1,191.08 387.570 671.940 2,339,484 376.659 164,410 23.86 5,214.593
72.54 1,078.670 35.770 637.150 2,00.455 292.587 158.380 18,36 4.592,55
68.570 1.109,380 367,210 678.810 1.891.576 269.155 172.48 17,490 4.557.181
71.39 1.187.280 378,10 687.510 2.05.09 284.722 179,26 16.242 4.618.672
82.270 1.357,880 427.93 708.35 2.115.976 280.662 173.120 18.775 5.146.188
923.4 14.1 4.44.72 7.!l7.56 24.3 3.85.",5 1.961.490 228.147 57.449.828
Pøg 10.14
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DECEMBER 2010 FACTORS
IDAHO
ANNUAL EMBEDDED COSTS
Period Endng December 2009
YEAR END BAlCE
Company Owned Hydro - West
Açcount Description Amount Mwh $/Mwh Difrential Refrence
535- 545 Hydro Opetion & Maintenance Expese 29.555,140 Page 2.7. West only
403HP Hyro Depreiation Expense 11.442.254 Page 2.15, West only
4041P Hydro Rellcensing Amozation 2,720.447 Page 2.1ß. West only
Tot West Hydro Opening Expense 43,717.841
330- 336 Hydro Elecric Plant in Service 509.192.400 Page 2.23, West only
302 & 182M Hydro Relicensing 100.881,734 Page 2.29. West only
108HP Hy Accumulated Depreciaton Res (211.569,917)Page 2.36. West only
1111P Hydro Relicensing Accumulated Reerve (11,454,352)Page 2.39. West on
154 Materals and Supplies (1.86)Page 2.32. Wes ony
West Hydro Net Rate Base 387,028,006
Preta Return 11.73%
Rate Base Renue Requirement 45,380,854
Annual Embedded Cost
West Hydr..Electrlc Resources 89,098,695 3,777,83 23.58 (ß5,082.413) MWh fro GRID
Mid C Contract
Account Descrpton Amount Mwh $/wh Difrential Refrence
555 Annual Mld-C Contr Cots 23.424,09 1.170,156 20.õ2 (24,332.377) GRID
Grant Reasonble Poron (15,523,615)(15,523.ß151 GRID
7,900,479 (39,855,992
Qualif Facilitis
Account Description Amount Mwh $/Mwh Diffrential Refnce
555 Utah Annual Quallie Facilites Costs 25,157.082 388,084 64.82 9,318,581
55 Oregon Annual Qualified Facliües Costs 39,578,386 275,120 143.86 28,350,172
55 Idaho Annual Qualifed Facilties Cots 4,135,847 75,849 54.67 1.048,256
555 WYU Annual Qualifed Facilies Costs
555 WVP Annual Qualifed Facilites Costs 723,797 11.373 63.64 259,842
555 Caillamia Annual Qualifed Facilties Costs 3,958,769 33.443 118.37 2,593,891
555 Washingto Annual Qualif Facilmes Costs 1,920,742 13,03 147.35 1,388,757
Total Qualifed Facilties Costs 75.474,423 796,704 94.73 42,959,299 GRID
All Otr Generaton. Resources
(Ex. West Hyro. Mid C, and QF)
Acount Descriptio Amount Mwh $/Mwh Reference
50- 514 Stem Opetin & Maintenanc Exse 991,43,159 Page 2.5
53-54 Ea Hyro Operation & Mainanc Expense 9.183,739 Page 2.7, East only
546-55 Other Generon Operation & Maintenance Expene 545,33,533 Page 2.8
55 01her Purchased P.. Cotrct 487,238,070 GRID les QF and Mlci
40910 Renewable Eney Proucn Tax Creit (113,34.472)Page 2.20
4118 502 Emisio Allowance (8.261.076)Pag 2..
456 James Rive / Litte Mountain Of (8,822,101)James River Adj (Tab 5)
456 Gre Tag Revenues (91,779,696)Gre Tag (Tab 3)
403P Stem Dereciation Expense 124,171,876 Page 2.15
403HP East Hyro Depre Exense 4,457.733 Page 2.15, East only
4030P Other Generaton Deation Expense 115,928.071 Page 2.15
403MP Mining Dep Expense 0 Page 2.15
4041P East Hyro Relicenslng Amorti 327,190 Page 2.16. East only
408 A_on of Plant Acqulsmon Costs 5,479,353 Page 2.17
T oll All Other Openg Expenses 2.061.350,379
310-316 Ste Eie Plant In Service 5.872.483.326 Pag 2.21
33-33 East Hyro Elecl Plant In Serce 125,087.529 Page 2.23. Eat only
30 & 186 East Hyro Relicenslng 9,841.735 Page 2.29. East only
34- 346 Other Elecc Plant in Serce 3.30.261,125 Page 2.24
399 Mining 48.80.833 Page 2.28
108SP Ste Accmulte Deprell Reerv (2,489.95.440)Page 2.38
108P Ot Gention Accumulate Deiati Res (294.931,95)Pag 2.36
108 Oth Acumulted Depreciaton Re (170.926.051 )Page 2.38. east only
108HP Eat Hy Aclate Dereiation Reere (42.780,373)Pag 2.36. Eest only
1111P East Hydro Reicin Acmuated Re (3.44.445)Page 2.39. East ony
114 Eletr Pla Acis Adustment 157.193.780 Page 2.31
115 Ac Proviion Acquis Adjustmet (96.326.873)Page 2.31
151 Fue Sto 195.574,734 Pag 2,32
253.16.253.19 Jont Owr WC Depoit (4,385,50)Pag 2.32
253.98 S02 emiSion Alances (33.04.213)Page 2.34
154 Maten & Supplie 81.516.215 Page 2.32
154 East Hy Matels & SupplieT_ Net Ra Ba 7,088.53,475Preta Ret 11.73Raie Ba Reve Reqireme ¡§i.m,m
An.. Embd Cos
Al 0l Geat Reoucas 2.893,736.051 70,903.94 40.81 MWh !T GRID
fõì Añ emd CÕts 3.66U6U5&76,64.638 40.00
Pag 10.19
ALOCTINS USIN
PROFORM LOADS
IDAHO REVISED PROTOCOL Pag 11.0 Total
Rebu Adjustment (Tab 11)
TOTAL
11.1 11.2 11.3 11.4 11.5 11.6
Brier U2
Overhaul Rebuttl Tax Impact Ma
Liquidate Medcae Subsidy Rebutl Avian Generation Major Plant Plant Addns
Total Norlized Damages Rebl SeWement Overhaul Expense Addlt Rebuttal Rebuttl
1 Operating Revenues:
2 General Business Revenues
3 Interdepartental
4 Special Sales 1,892,013
5 Oter Oprating Revenues
6 T olal Operang Revenues 1,892.013
7
8 Operating Expenses:
9 Steam Production 29,96 (73.017)
10 Nuclear Producon
11 Hydro Producton
12 Other Power Supply 1,558,631 (8,414)
13 Transmission 158,394
14 Distrbuton
15 Customer Accounting
16 Customer Service & Info
17 Sal
18 Adminislrative & General (4,999)(4,999)
19 Total O&M Expenses 1,741,988 (4,999)(81,431)
20 Deprecilion (46,716)(313)(1,497)
21 Amortzaon
22 Taxes Othr Than Income
23 Incme Taxes: Federal (13,132.415)166 1,670 1,244 27,207 (13.198.954)
24 Siate (1.784,477)23 227 169 3,697 (1,793.519)
25 Deferred Income Taxes 15.105.976 (70)(845)14,992,472
26 Investent Tax Credit Adj.
27 Misc Revenue & Expense (301.491)
28 Total Operang Expenses:1.582,865 (194)(3.102)(929)(50.527)0
29
30 Operating Rev For Return:309,148 194 3,102 929 50,527 (0)
31
32 Rate Base:
33 Elect Planlln Service (2,008,08)(13,248)(74,490)(1.920,347)
34 Plant Held fo Future Use
35 Misc Dered Debit
36 Ele Plant Acq Adj
37 Nuclear Fuel
38 Prepyments
39 Fuel Stock
40 Material & Supplies
41 Work Capl
42 Weathizn Loans
43 Mlsc Rate Base
44 Total Elric Plt:(2,008,08)(13,248)(74.490)(1,920.347)
45
46 Deuctions:
47 Accm Prov For Deprec 59,898 313 1,487
48 Ace Prov For Amo
49 Accum Def Incme Tax (15,105,976)70 845 (14,992,472)
50 Unamortd ITC
51 Custoer Adv For Const
52 Custor Service Deit
53 Miscellaneous Deduct 301,491
54
55 Total Deductions:(14.744,590)383 2,342 (14.992,472)
58
57 Total Rate Base:(16,752,675)(12,865)(72,148)(1.920,347)(14,99,472)
68
59
60 Esll1ed ROE Impct 0.451%0.00 0.001%0.002%0,017%0.038%0.30%
61
62
63
84 TAX CALCULATIN:
65
66 Opeatg Reven 498.233 313 4,999 1,497 81,43167 Ot De
68 Intl (AFUDC)
69 Intest70 Sc "M Adns (68.39)(313)(68.085)71 Sch "M Deon 38,745,496 (497)(2,227)39.44,729
72 Inc Befor Tax (39,30,662)497 4,99 3,725 81,431 (39.50,815)
73
74 S_ In Taxes (1,784,477)23 227 169 3.697 (1,793.519)
75
76 Taxab In (37,521,165)474 4.772 3,558 77,734 (37,711,296)
77
78 Fed tnc Taxes (13,132,415)186 1.670 1,244 27,207 (13,198,954)
IDAHO REVISED PROTOCOL Page 11.0.1 Total
Rebutal Adjustmnts (Tab 11)
TOTAL
11.7 11.8 11.9 11.10 0 0 0
Rebuttl Rebuttl
Depreciation Depreciation Rebu Net Rebuttl S02
Expense Reserve Pow Cost Sales 0 0 0
1 Operating Revenues:
2 General Busines Revenues
3 Interdepartntal
4 Special Sales 1.892.013
5 Other Operating Revenues
6 Tota Operating Revenues 1,892.013
7
8 Operating Expenses:
9 Steam Producton 102.979
10 Nuclear Producton
11 Hydro Producion
12 Other Power Supply 1.567,04
13 Trasmission 158,394
14 Distribuon
15 Custom Accounting
16 Custome Service & Info
17 Sales
18 Administrative & General
19 Total O&M Expenses 1.828,417
20 Depreciation (44,906)
21 Amortzation
22 Taxes Other Than Income
23 Inco Taxes: Federal 15,003 21,248
24 Sta 2.039 2.887
25 Defrr Inco Taxes 114,419
26 Investme Tax CredR Adj.
27 Misc Revenue & Expense (301,491)
28 Total Operating Expenses:(27,863)1.852.553 (187,072)
29
30 Operating Rev For Return:27.863 39,461 187.072
31
32 Rate Base:
33 Eleet Plant In Servic
34 Plant Held for Future Use
35 Misc Defered Debi
36 Ele Plant Acq Ad)
37 Nuclear Fuel
38 Prepaymets
39 Fuel Stock
40 Material & Supplies
41 Worng Capitl
42 Weathritin Loans
43 Mlc Rate Base
44 Tota Eleet Plant:
45
46 Dectons:
47 Acc Prov For Deprc 58,085
48 Accum Prov For Amor
49 Accum De Income Tax (114,419)
50 Unamod ITC
51 Custo Adv For Const
52 Customer Seric Deosits
53 Micella Deductns 301,491
54
56 Tota DedUCns:58,085 187,072
56
57 Tot Rate Base:58.085 187,072
58
59
60 Estima ROE Impac 0.010%-0.001%0.014%0.061%0.00%0.00%0.000%
61
62
63
64 TAX CALCUlTION:
65
66 Operating Revenue 44.90 63.59 301.49167 Otr De
68 Int (AFUOC)691_t70 Sc "M" Addl71 Sc "M De 301,491
72 In Bee Tax 44,90 63.59
73
74 Sta In Taxes 2,039 2,887
75
76 Tllable Ine 42.867 60.709
77
78 Fedal Inc Taxes 15.00 21,248
Rocky Mountain Power PAGE 11.1
Idaho General Rate Case - December 2009
Bridger U2 Overhaul Liquidated Damages
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR % ALLOCATED REF#
Adjustment to Rate Base:
Steam Plant Capital 312 3 (240,497)SG 5.508%(13,248)11.1.1
Steam Plant Depreciation Reserve 108SP 3 5,691 SG 5.508%313 11.1.1
Adjustment to Expense:
Steam Plant Depreciation Expense 403SP 3 (5,691)SG 5.508%(313)11.1.1
Tax Impacts:
Schedule M Adjustment SCHMAT 3 (5,691)SG 5.508%(313)
Schedule M Adjustment SCHMDT 3 (9,019)SG 5.508%(497)
Deferred Income Tax Expense 41110 3 (1,263)SG 5.508%(70)
Accumulated Def Inc Tax Balance 282 3 1,263 SG 5.508%70
Description of Adjustments:
This adjustment adds in liquidated damages for an overhaul that was done on Bridger Unit #2 in CY2009.
Page 11.1.1
Rocky Mountain Power
Idaho General Rate Case - December 2009
Bridger U2 Overhaul Liquidated Damages - 10 GRC Dec09 - Rebuttal
Total Liquidated Damages
Liquidated Damages Reflected in the GRC
Remaining Liquidated Damages
RMP Remaining Liquidated Damages
625,000
264,254
(360,746)
(240,497) Ref. 11.1
Depreciation Rate 2.366%
Depreciation Expense
Depreciation Reserve
(5,691) Ref. 11.1
5,691 Ref. 11.1
Rocky Mountain Power
Idaho General Rate Case - December 2009
Medicare Subsidy Rebuttal
PAGE 11.2
TOTAL
ACCOUNT ~ COMPANY FACTOR
IDAHO
FACTOR % ALLOCATED REF#
Adjustment to Expense:
Regulatory Asset Amortization 930 (4,999)ID Situs (4,999)
Description of Adjusbnent:
The Company filed an application with the Commission to defer and amortize the initial write off related to a
change in law. This rebuttal adjustment includes the reduction in the yearly amortization amount due to accounting
updates through March, 2010 instead of December 2009 as originally fied.
Description of Adjustment:
This rebuttal adjustment removes the capital addition related to various transmission improvement projects
resulting from the Avian Settlement Agreement as their accumulated sum falls below the $5 millon capital addition
threshold.
Rocky Mountain Power
Idaho General Rate Case - December 2009
PAGE 11.4
Rebuttal Generation Overhaul Expense
Adjustment to Expense:
Generation Overhaul Exp - Steam
Generation Overhaul Exp - Other
510
553
(1,325,528)
(152,748)
(1,478.277)
SG
SG
IDAHO
FACTOR %ALLOCATED REF#
5.508%(73,017)Below
5.508%(8,414)Below
(81,431)
TOTAL
ACCOUNT IY COMPANY FACTOR
Adjustment Detail:
Generation Overhaul Exp - Steam Revised
Generation Overhaul Exp - Steam As Filed
506,600
1,832,129
( 1.325,528)
11.4.1
Generation Overhaul Exp -Other Revised
Generation Overhaul Exp - Other As Filed
(4,057,750)
(3.905.002)
(152.748)
11.4.1
Description of Adjustment:
This rebuttal adjustment recalculates the Company's original adjustment without escalation of the historical costs.
It does not recalculate the average of the newer plants using years 2007-10.
Rocky Mountain Power
Idaho General Rate Case. December 2009
Rebuttal Generation Overhaul Expense
FUNCTION: OTHER
Period
Year Ending December 2006
Year Ending December 2007
Year Ending December 2008
Year Ending December 2009
4 Year Average
New Plant Overhaul Expense
Lake Side Plant - 4 Year Average
Currant Creek Plant - 4 Year Average
Chehalis Plant - 4 Year Average
Total New Plant Overhaul Expense
Total 4 Year Average - Other
Overhaul Expense
2,940,000
2,860,000
1,725,000
2,552,000
2,519,250
Year Ending December 2009 Overhaul Expense - Other
Total 4 Year Average - Other
Adjustment
FUNCTION: STEAM
Period
Year Ending December 2006
Year Ending December 2007
Year Ending December 2008
Year Ending December 2009
4 Year Average
Overhaul Expense
29,613,264
28,560,541
20,030,017
25,392,474
25,899,074
Year Ending Dec 2009 Overhaul Expense - Steam
Total 4 Year Average - Steam
Adjustment
Page 11.4.1
Escalation Rates
to Dec 2009 * Escalated Expense10.43% 3,246,6126.64% 3,049,9861.22% 1,725,000
2,552,000
2,643,400
1,031,000
2,023,000
754,000
3,808,000 Ref 11..2
6,327,250
10,385,000 Ref 11.4.2
6,327,250
(4,057,750) Ref11.4
Escalation Rates
to Dec 2009 * Esclated Expense11.04% 32,882,9337.29% 30,643,282-0.25% 19,979,722
25,392,474
27,224,603
25,392,474 Ref11.4.2
25,899,074
506,600 Ref11.4
Rocky Mountin Power
Idaho General Rate Case. December 2009
Rebuttal Generation Overhaul Expense
Page 11.4.2
Existing Units
Plants. Oter
Calendar Calendar Calendar Calendar
Yr 2006 Yr 2007 Yr 2008 Yr 2009
73,934 2,677,913 83,913 418,189
723,024 24,146 1,730,915 1,676,722
30,900 3,279,981 5,824,658 6,478,000
2,290,000
3,910,432 8,171,859 (95O,900)
7,575,000 (39,000)769,000
3,648,974 4,864,64 1,341,431 6,895,563
5,629,000
6,60,000
925,000 1.300.00 1,156,000
44a.OO 1,376,000 743,000
745,000 90,000 370,000 495,000
5.90,000 6,815,000 4.427,000 5,214.00
2,383,000 2.860.000 1,725,000 2.023,000
139,000 529,000
418,000
32,55.264 31,420,541 21,755,017 27,944,474
29,613,264 28,560,541 20,030,017 25,392,474 R.1.11.'.1
2,94,000 2,860,000 1,725.000 2,552,000
$32.55,264 $31,20,541 $21,755,017 $27,94,474
Plants. Steam
Blundell
Carbon
DaveJohnston
Gadsby
Hunter
Huntington
Naughton
Wyodak
Cholla
Colstrip
Craig
Hayden
JimBridger
Hermston
LiIeMt
Camas
WValley
Total. includes Sleam and Other
By Function
Steam
Other
Total
New Generang Units'
Restiiment in December 2009 Dollars
I Actual Budoe! 2010 Dolars!i
r Calendar
I
Calendar
I
Calendar Calndar
I
Calendar I Calndr I 4 Year
Yr 207 Yr2008 Yr2009 Yr 2010 Yr2011 Yr2012 Averaoe Meyets ad
1,523,000 1,216,000 5,121,000 232.000 .2,023,000 2,023,000
54,000 1,001,000 2,579,000 593,000 1,031,000 386,250
.1,711.000 1,305,000 754,00 427,750
3,808,000 2,837,000
106.64%101.22%99.80%99.80%99.80%
r Calendar
I
Calendar
I
Calendar Calendar
I
Calendar I Calendar J 4 Year Averged
Yr 2007 Yr 2008 Yr2009 Yr 2010 Yr20l1 Yr 2012 Ave""Years
1,624,171 1,230,839 5,121,000 231,535 2,051,886 2007.20'0
550,639 1,001.000 2,573,828 591.811 1,031,367 20.2011
1,711,000 .1,302,383 753,34 200012
1,624,171 1,781,478 7,833,000 231,535 2,573,828 1,894,194 3,836,599
Currt Creek
Lake Side
Chehalis
Restatement Percentage
Currnt Creek
LakeSide
Chehalis
Below
'Curnt Creek. Lake Sid, & Chehalis are all Functon. Other
December 2009 Overl Expense. Other
Pre.2oo7 Plant
2009 Currt Crek, Lake Side. and Chehalis:
2,552,000
7,833.000 Ab""
10,385,000 R.I. 11.'.1
Rocky Mountain Power PAGE 11.5
Idaho General Rate Case . December 2009
Major Plant Additions Rebuttal
TOTAL IDAHO
ACCOUNT .I COMPANY FACTOR FACTOR % ALLOCATED REF#
Adjustment to Rate Base:
Steam Production 312 3 (23,316,784)SG 5.508%(1,284,405)11.5.1
Hydro Production 332 3 219,994 SG-P 5.508%12,118 11.5.1
Other Production 343 3 (8,077,338)SG 5.508%(444,940)11.5.1
Transmission 355 3 2,943,073 SG 5.508%162,119 11.5.1
Mining Plant 399 3 (5,745,000)SE 6.358%(365,240)11.5.1
(33,976,054 )(1,920,347)
Descrlptionof Adjustment:
This adjustment reduces the Major Plant Addition adjustment included in the filing for updated project forecasts
and in service dates.
The coresponding depreciation expense and reserve adjustments have also been updated.
Rocky Mountain Power PAGE 11.6
Idaho General Rate Case - December 2009
Tax Impact Major Plant Additions Rebuttal
TOTAL IDAHO
ACCOUNT Type COMPANY FACTOR FACTOR %ALLOCATED REF#
Adjustment to Tax:
Sch M Additions - Mining SCHMAT 3 (207,307)SE 6.358%(13,180)
Sch M Additions- Steam Production SCHMAT 3 (551,719)SG 5.508%(30,391)
Sch M Additions- Other Production SCHMAT 3 (327,328)SG 5.508%(18,031)
Sch M Additions- Transmission SCHMAT 3 59,147 SG 5.508%3,258
Sch M Additions - Hydro Production SCHMAT 3 4,696 SG 5.508%259
(1,022,512)(58,085)
Deferred Tax Exp- Mining 41110 3 78,675 SE 6.358%5,002
Deferred Tax Exp- Steam Production 41110 3 209,383 SG 5.508%11,534
Deferred Tax Exp- Other Production 41110 3 124,224 SG 5.508%6,843
Deferred Tax Exp- Transmission 41110 3 (22,447)SG 5.508%(1,236)
Deferred Tax Exp- Hydro Production 41110 3 (1,782)SG 5.508%(98)
388,053 22,044
Accum DITBAL- Mining 282 3 (78,675)SE 6.358%(5,002)
Accum DITBAL - Steam Production 282 3 (209,383)SG 5.508%(11,534)
Accum DITBAL - Other Production 282 3 (124,224)SG 5.508%(6,843)
Accum DITBAL - Transmission 282 3 22,447 SG 5.508%1,236
Accum DITBAL- Hydro Production 282 3 1,782 SG 5.508%98
(388,053)(22,044)
Sch M Deductions-Mining SCHMDT 3 6,961,508 SE 6.358%442,579
Sch M Deduction- Steam Production SCHMDT 3 156,044,734 SG 5.508%8,595,721
Sch M Deduction- Other Production SCHMDT 3 99,627,077 SG 5.508%5,487,955
Sch M Deduction- Transmission SCHMDT 3 448,970,356 SG 5.508%24,731,523
Sch M Deduction- Intangible Plant SCHMDT 3 477,934 SG 5.508%26,327
Sch M Deductions- Hydro Production SCHMDT 3 2,952,239 SG 5.508%162,624
715,033,847 39,446,729
Deferred Tax Exp- Mining 41010 3 2,641,962 SE 6.358%167,963
Deferred Tax Exp- Steam Production 41010 3 59,220,537 SG 5.508%3,262,162
Deferred Tax Exp Other Production 41010 3 37,809,472 SG 5.508%2,082,734
Deferred Tax Exp- Transmission 41010 3 170,388,740 SG 5.508%9,385,860
DeferredTax Exp- Intangible Plant 41010 3 181,381 SG 5.508%9,991
Deferred Tax Exp- Hydro Production 41010 3 1,120,404 SG 5.508%61,717
271,362,495 14,970,428
Accum DITBAL- Mining 282 3 (2,641,962)SE 6.358%(167,963)
Accum DITBAL - Steam Production 282 3 (59,220,537)SG 5.508%(3.262,162)
Accum DITBAL - Other Production 282 3 (37,809,472)SG 5.508%(2,082,734)
Accum DITBAL - Transmission 282 3 (170,388,740)SG 5.508%(9,385,860)
Accum DITBAL . Intangible Plant 282 3 (181,381 )SG 5.508%(9,991 )
Accum DITBAL- Hydro Production 282 3 (1,120,404)SG 5.508%(61,717)
(271,362,495)(14.970,428)
Description of Adjustment:
This adjustment incorporates the tax impacts of the Major Plant Addition rebuttal adjustment. This adjustment also
includes bonus depreciation.
Rocky Mountain Power
Idaho General Rate Case - December 2009
Rebuttal Depreciation Expense
PAGE 11.7
TOTAL IDAHO
ACCOUNT Type COMPANY FACTOR FACTOR % ALLOCATED REF#
Adjustment to Expense:
Steam Production 403SP 3 (551,719)SG 5.508%(30,391)Below
Hydro Production 403HP 3 4.696 SG-P 5.508%259 Below
Other Production 4030P 3 (327,328)SG 5.508%(18,031)Below
Transmission 403TP 3 59,147 SG 5.508%3.258 Below
(815.205)(44,906)
Adjustment Detail:
Updated
Steam Production
Hydro Production
Other Production
Transmission
Intangible Plant
13,831,844
130,577
10,256,941
18,989,404
461,144
43,669,911 11.7.1
As Filed
Steam Production
Hydro Production
Other Production
Transmission
Intangible Plant
14,383,564
125,881
10,584,269
18,930,257
461,144
44,485,115
Adjustment
Steam Production
Hydro Production
Other Production
Transmission
Intangible Plant
(551,719)
4,696
(327,328)
59,147
(815,205)
Description of Adjustment:
This adjustment to depreciation expense reflects the update that was made to the Major Plant Addition adjustment
in the rebuttal filing.
Rocky Mountain Power PAGE 11.8
Idaho General Rate Case - December 2009
Rebuttal Depreciation Reserve
TOTAL IDAHO
ACCOUNT Im COMPANY FACTOR FACTOR % ALLOCATED REF#
Adjustment to Reserve:
Steam Production 108SP 3 551,719 SG 5.508%30,391 Below
Hydro Production 108HP 3 (4,696)SG-P 5.508%(259)Below
Other Production 1080P 3 327,328 SG 5.508%18,031 Below
Transmission 108TP 3 (59,147)SG 5.508%(3,258)Below
Mining Plant 108MP 3 207,307 SE 6.358%13,180 Below
1,022,512 58,085
Description of Adjustment:
This adjustment to depreciation reserve reflects the update that was made to the Major Plant Addition adjustment
in the rebuttl fiing.
Page 11.8.1
Rocky Mountain Powr
Idaho General Rate Case - December 2009 - Rebuttal
Major Plant Addtion Detail. Jan2010 to Dec2010 'U¡ílld
Plant Depreciation Janl0 to DeclO Piant Incremental Reserve on
Prolact Dascription Account Factr In-Service Date Account Depreciaton Rate Additions PlentAdds
Steam Production
Dave Johnston: U3 502 & PM Emission Cnt~ Upgrades 312 SG May-l 0 108SP 2.366%299.083.211 (7.076,875)
Huntiton Ul Clean AI - PM 312 SG Nov-l0 108SP 2.366%66,881,032 (2,055.770)
Hunter. 301 Turbine Upgrade HP/iP/LP 312 SG Apr-l0 108SP 2.366%30.384,402 (718,952)
Huntington: UL Turbine Upgrade HP/IPILP 312 SG Novl0 108SP 2.366%30,172,885 (713,948)
Ul Huntington Clean Air - 502 312 SG Nov-l0 l08SP 2.366%6,493,942 (153.659)
Jim Bridger: UL 502 & PM Em Cnlr Upgrades 312 SG Jun-l0 108SP 2.366%14,975,646 (354,352)
Dave Johnston: U3 Low Nox Bumers 312 SG Aug-l0 108SP 2,366%17,586,539 (416,131)
Hunter 301 Main Contr Replacement 312 SG Apr.l0 108SP 2.366%9,559.675 (226,200)
Dave Johnton: U3 - Replace Bollerrrurbine Contrs 312 SG May-l0 108SP 2,366%10,767.578 (254,781)
Jim Bridger UL Turne Upgrade HP/iP 312 SG Jun-l0 108SP 2,366%9,140.208 (216,275)
Huntington: UL Clean Air - NO.312 SG Novl0 108SP 2.366%9.344.367 (221,106)
Jim Bridger. UL Reeater Replacemnt 10 312 SG Jun-l0 108SP 2.366%8,087,849 (190.901)
Huntngton: ul Economizer Replacement 312 SG Nov.l0 l08SP 2,36%8,011,393 (189,565)
Huntington Water Efficiency Mgt Projec 312 SG Jun-l0 108SP 2.36%8,971,432 (212,281)
Jim Bridger. UL Clean Air - NO.312 SG Jun-l0 108SP 2,366%6,042,280 (142,972)
Hunter. 301 Economizer Relacement 312 SG Apr-I 0 108SP 2.366%6,301,709 (149.110)
Huntington: UL Boiler Finish SH Pendants Replacent 312 SG Nov-I 0 108SP 2.36%5,807,429 (137.415)
Jim Bridger. UL Generator Rewnd 312 SG Jun-l0 1085P 2,366%5.857,136 (136,591)
Hunter: 301 Low Temp. SH Replacement 312 SG Apr-I 0 108SP 2.36%5,470.087 (129,432)
Dave Johnston: U3 - Horzontal SH Replace 312 SG May-l 0 108SP 2.36%5,643,210 (133,529)
Steam Produelon Totl 584,562,010 (13,831,84)
Hydro Produelon
INU 11.5 Lemolo 1 FQlbay expansion & We 33 SG-P Aul0 108HP 2.135%6,117,381 (130.577
Hydro Production Total 6,117,381 (130.577
Othr Produet
Dunlap i Win Project 343 SG Nov-l0 1080P 4.052%253.106,361 (10.256,941)
Otr Prodelon Total 253.106,361 (10.256.941)
Transmission
Populus to Termlnat (Populus to Ben Lomond)35 SG No-l0 108TP 2.010%402,938,994 (8.97.835)
Populus to Terinal (Populus to Be Lomnd)355 SG Del-I 0 10BTP 2.010%145,199,007 (2,918.05)
Poplus to Terinal (Ben Lomond to Terminal)355 SG Mar.l0 108TP 2.010%190,877118 (3,836.043)
Populus to Terinal (Ben Lomond to Terminal)355 SG Apr-l0 108TP 2.010%7,340.2n (147,517)
Poplus to Ternal (Ben Lomond to Terminal. residual clos)355 SG 0eel0 108TP 2.010%6,727,289 (135,198)
Thre Peaks Sub: Instal 345 kV Substation. Phase II 355 SG Jun-l0 108TP 2,010%51,134,840 (1,027,653)
Camp Wiliams - 90t Sou Double Circuit 345 kV line 355 SG Dee-l0 108TP 2.010%45.00,000 (912,400)
Re B\Ie-St Geoge 136 kv dbl ckt, (345 kv Const)355 SG May-l 0 108TP 2.010%22,651.000 (455,215)
Pinto 345 kV Series Capacitor 355 SG Nov-l0 108TP 2,010%15,028,000 (302.017)
Dunlap Ranch Wind Ferm Phase 1 Internecton 355 SG Aul0 108TP 2.010%10.50,00 (211.018)
Uppe Gre Rier Bain Super Proec - Trensmlss Pert 355 SG 0-10 108TP 2.010%10,025,204 (201,476)
Oqu. New 345-138 kV Sub & 138 kV Swlhyard 355 SG Jun-l0 10BT 2.010%8,416,076 (169,137)
Parr Gap Cont Nw 2309kV Sub 355 SG Jun-l0 l08TP 2.010%9,900.000 (198,960)
Line 37 Conv to 1151N Bid Nickel Mt Sub - Tra 355 SG Mer-l0 I08TP 2.010%9,570,203 (192,332)
Chappe Creek 230 kV Clme.. Ener 20 MW Phae II 35 SG Dee-l0 108TP 2.010%5,496,321 (110,459)
Comun Par Convert to 115-12.5 kV. Transmision Part 35 SG Qe10 108TP 2.010%3,686,621 (74,09)
Transmission Tota 94.890.952 (18.989.40)
Intangibl
TriP ii Enery Tradin Syss Capital 303 SG Dec-l0 L111P 4.020%11,470,408 (461,144)
Intngle Total 11,470.408 (461.144)
Mining
Deer Cre-Restrct Lonll Syste 399 SE De-l0 108MP 3.608%18.160.00 (655.30)
Mining Totl 18.160.000 1655.30)
1,818,307,112 144.325,211 )Rë 11.8
Description of Adjustment:
This adjustment incorporates the net power cost adjustments in the Company's rebuttal testimony.
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Page 11.9.2
Rocky Mountain Power
Idaho General Rate Case - December 2009
Net Po\'Ver Cost Adjustment.. Rebuttal
Rebuttal
Rebuttal Filed Adjustment
TOTAL TOTAL TOTAL
ACCOUNT COMPANY COMPANY COMPANY
Adjustment to Revenue:
Sales for Resale (Account 447)
Existing Firm PPL 447 2,811,079 2,811,079
Existing Firm UPL 447 2,349,900 2,349,900
Post-Merger Firm 447 217,459,147 183,111,971 34,347,176
Non-Firm 447 (1,068,483)(1,068,483)
Total Sales for Resale 221,551,644 187,204,468 34,347,176
Adjustment to Expense:
Purchased Power (Account 555)
Existing Firm Demand PPL 555 26,852,544 26,852,544
Existing Firm Demand UPL 555 41,455,319 41,455,319
Existing Firm Energy 555 (28,211,629)(28,211 ;629)
Post-merger Firm 555 42,556,078 48,109,163 (5,553,085)
Secondary Purchases 555 19,022,490 19,022,490
Seasonal Contracts 555
Other Generation 555 33,105,578 34,187,931 (1,082,352)
Total Purchased Power Adjustments:134,780,380 141,415,818 (6,635,437)
Wheeling Expense (Account 565)
Existing Firm PPL 565 (2,960,982)(2,960,982)°
Existing Firm UPL 565 (820,285)(820,285)
Post-merger Firm 565 23,146,266 23,179,140 (32,874)
Non-Firm 565 1,469,783 (1,050,141 )2,519,925
Total Wheeling Expense Adjustments:20,834,783 18,347,732 2,487,051
Fuel Expense (Accounts 501, 503, 547)
Fuel Consumed - Coal 501 114,712,374 113,299,594 1,412,780
Fuel Consumed - Gas 501 (29,773,826)(29,856,185)82,359
Steam from Other Sources 503 (223,647)(223,647)
Natural Gas Consumed 547 42,386,776 13,052,907 29,333,868
Simple Cycle Combustion Turbini 547 (21,527,550)(22,591,198)1,063,648
Cholla I APS Exchange 501 1,226,184 1,094,564 131,620
Total Fuel Expense Adjustments:106,800,311 74,776,036 32,024,276
Total Power Cost Adjustment 40,863,830 47,335,117 (6,471,288)
Ref 11.9.1 Ref 11.9
Remove Power Cost Deferrals 555 (20,481,246)(20,481,246)
Rocky Mountain Power
Idaho General Rate Case - December 2009
Period Ending
December-10
SPECIAL SALES FOR RESALE
Pacific Pre Merger
Post Merger
Utah Pre Merger
Non Firm Sub Total
TOTAL SPECIAL SALES
PURCHASED POWER & NET INTERCHANGE
BPA Peak Purchase
Pacific Capacity
Mid Columbia
MisclPacific
O.F. eontractslPPL
Pacific Sub Total
Gemstate
GSLM
OF ContractsfUPl
IPP Layoff
UP&L to PP&L
Utah Sub Total
APS Supplemental p27875
Blanding Purchase p379174
BPA Reserve Purchase
Chehalis Station Service
Combine Hils Wind p160595
Constellation p257677
Constellation p257678
Constellation p268849
Deseret Purchase p194277
Georgia-Pacific Camas
Hermiston Purchase p99563
Hurricane Purchase p393045
Kennecott Generation Incentive
LADWP p491303-4
MagCorp p226
MagCorp Reserves p510378
Morgan Stanley p189046
Morgan Stanley p272153-6-8
Morgan Stanley p272154-7
Nucor p34856
P4 Production p137215fp145258
Rock River Wind p1 00371
Roseburg Forest Products p312292
Three Butes Wind p46057
Top of the World Wind p575862
Tri-State Purchase p27057
Wolverine Creek Wind p244520
BPA So. Idaho p64885/p83975/p6705
PSCo Exchange p30325
TransAlt p371 348371 34
Seasonal Purchased Power
Morgan Stanley p24440
Moran Stanley p244841
UBSp268848
UBS p268850
Page 11.9.3
Study Results
MERGED PEAK/ENERGY SPLIT
($)
Merged Pre-Merger Pre-Merger
01/ 0-12/1 0 lÆ ~Non-Firm Post-Merger
25,036,260 25,036,260
805,993,310 805,993,310
25,490,589 25,490,589
.._-_...._----_.._---_._..00-..-..-..--------- _________.._.._____------------------....__.._---_.._---...
856,520,160 50,526,850 805,993,310
57,615,000
1,470,755
29,774,072
6,326,113
67,443,841
57,615,000
600,000
8,932,222
1,311,801
6,571,976 28,852,243
870,755
20,841,851
5,014,313
32,019,623
162.629,782 75,030,998 58,746,542 28,852,243
2,716,400 2,716,400
107,365,737
25,490,589
21,091,915 9,039,392
25,490,589
77,234,430
135,572,726
4,415,996
28,864
239,962
138,194
3,911,516
46,582,504 11,755,792 77234,430
4,415,996
28,864
239,962
138,194
3,911,516
31,867,569
6,434,764
97,281,918
145,210
10.824,184
774,380
4,370,900
10,683,600
1,485,000
1,572,00
4,885,800
16,193,520
5,041,688
8,767,111
20,598,497
12,687,518
11,359,280
9,748,726
(56,234)3,600,00
(1,644,00)
31,867,569
6,434,764
97,281,918
145,210
10,824,184
774,380
4,370,90
10,683,600
1,485,000
1,572,000
4,885,800
16,193,520
5,041,688
8,767,111
20,598,497
12,687.518
11,359,280
9,748,726
(56,234)3,600,00
(1,64,00)
Rocky Mountain Power
Idaho General Rate Case. December 2009
Period Ending
December. 7 0
Short Term Firm Purchases
New Firm Sub Total
Wind Integration Charge
Non Firm Sub Total
TOTAL PURCHASED PW & NET INT.
WHEELING & U. OF F. EXPENSE
Pacific Firm Wheeling and Use of Facilities
Utah Firm Wheeling and Use of Facilties
Post Merger
Nonlirm Wheeling
TOTAL WHEELING & U. OFF. EXPENSE
THERMAL FUEL BURN EXPENSE
Carbon
Cholla
Colstrip
Craig
Chehalis
Currant Creek
Dave Johnston
Gadsby
Gadsby CT
Hayden
Hermiston
Hunter
Huntington
Jim Bridger
Lake Side
Utile Mountain
Naughton
Wyodak
TOTAL FUEL BURN EXPENSE
OTHER GENERATION EXPENSE
Blundell
TOTAL OTHER GEN. EXPENSE
NET POWER COST
Page 11.9.4
Study Results
MERGED PEAK/ENERGY SPLIT
($)
Merged
01/10=12110
7,054,508
Pre-MergerJÆ Pre-Merger~.N Post-Merger
7,054,508
272,410,464
33,105,578
272,410,464
33,105,578
603,718,551 121.613,502 70,502,334 411,602,715
26,972,928 26,972,928
108,410,485 108,410,485
2,612,580 2,612,580
--------------------------_........-----_. -_....---------_........_---_.._-_...._--....--_......__..................
137,995,993 26,972,928 2,612,580 108,410,485
20,663,737 20,663,737
54,217.555 54,217,555
11,524,649 11,524,649
20,271,843 20.271,843
132,777,904 132,77,90
109,269,611 109,269,611
48,426,653 48,426,653
6,746,966 6,746,966
13,961,570 13,961,570
11,290,102 11,290,102
60,461,446 60,461,446
113,48,800 113,484,800
104,947,002 104,947,002
183,646,047 183,646,047
157,018,402 157,018,402
9,113,308 9,113,308
97,728,642 97,728,642
19,111,477 19,111,477--------------------_..........--- -_.._....-----_..__......----_..-......_------_....__.._-_..-..
1,174,661,714 1,174,661,714
3,373,929 3,373,929
3,373,929 3,373,929======= =========--=== ====-
1,063,230,027 98,059,581 70,502,334 1,180,648,223 (285,980,110)========== ======== ========= ======= =======
Ref 11.9.1
Rocky Mountain Power
Idaho General Rate Case. December 2009
Rebuttal S02 Sales
PAGE 11.10
Adjustment to Taxes:
Schedule M Deduction
DIT Expense
TOTAL IDAHO
ACCOUNT~COMPANY FACTOR FACTOR % ALLOCATED REF#
4118 (4,742,268)SE 6.358%(301,491 )Below
190 1 (1,799,738)SE 6.358%(114,419)Below
25398 1 4,742,268 SE 6.358%301,491 Below
SCHMDT 4,742,268 SE 6.358%301,491 Below
41010 1,799,738 SE 6.358%114,419 Below
Adjustment to Income:
Add CY 2010 Amortization
Adjustment to Rate Base:
Accumulated Deferred Income Taxes
Regulatory Deferred Sales
Adjustment Detail:
Rebuttl 5 Year Average
Remove CY 2009 Allowance Sales
Add CY 2010 Amortization
Schedule M Deduction
DIT Expense
3,790,891 11.10.1
(8,261,076)11.10.1
12,540,609 11.10.1
(33,044,213)11.10.1
8,261,076 11.10.1
3,135,161 11.10.1
3,790,891
(3,518,808)
14,340,347
(37,786,481)
3,518,808
1,335,423
Accumulated Deferred Income Taxes
Regulatory Deferred Sales
As Filed
Remove CY 2009 Allowance Sales
Add CY 2010 Amortization
Accumulated Deferred Income Taxes
Regulatory Deferred Sales
Schedule M Deduction
DIT Expense
Rebuttl Incremental Adjustment
Remove CY 2009 Allowance Sales
Add CY 2010 Amortization
Accumulated Deferred Income Taxes
Regulatory Deferred Sales
(4,742,268)
(1,799,738)
4,742,268
Schedule M Deduction
DITExpnse
4,742,268
1,799,738
Description of Adjusbnent:
This adjustment reduces the amortization of 802 sales from 15 years to 5 years and includes the corresponding
rate base and tax impacts.
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Case No. PAC-E-1O-07
Exhbit No. 80
Witness: Steven R. McDougal
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Rebuttal Testimony of Steven R. McDougal
Updated LGAR Calculation
November 2010
Rocky Mountain Power
Exhibit No. 80 Page 1 of 3
Case No. PAC-E-10-07
Witness: Steven R. McDougal
Idaho Public Utilties Commission Production Request 5
Unbundled Production Revenue Requirement (Excluding NPC)
PAC-E-10-07
Unbundled Production Revenue Requirement
Description Amount Source
1 Production - Return On Investment 877,766,533 Rebuttal Exhibit 2 paae 10.19
2 Production - Expense 2,188,443,123 Rebuttal Exhibit 2 page 10.19
3 Production - Revenues (856,520,160)Rebuttal Exhibit 2 page 11.9.1
Production Revenue Requirement 2,209,689,497 (Line 1 + Line 2 - Line 3)
System Load 57,460,901 Net Power Cost Study
Production $ per MWH $38.46
PAC-E-10-07
Unbundled Production Revenue requirement (Excluding Net Power Costs)
Description Amount Source
1 Production - Return On Investment 877,766,533 Rebuttal Exhibit 2 page 10.19
2 Production - Expense 2,188,443,123 Rebuttal Exhibit 2 page 10.19
3 Production - NPC Expenses (1,781,754,194)Rebuttal Exhibit 2 page 11.9.1
Production Revenue Requirement
(Excluding NPC)1,284,455,462 (Line 1 + Line 2 - Une 3)
System Load 57,460,901 Net Power Cost Study
Production $ per MWH $22.3a:
PAC-E-08-07
Unbundled Production Revenue Requirement (Per IPUC Order No.30715)
Description Amount Source
1 Production - Return On Investment 615,420,689 JAM Tab ECD
2 Production - Expense 3,624,067,686 JAM Tab ECD
3 Production - Revenues (2,242,830,255)RAM Tab 5, Adj No 1
Production Revenue Requirement 1,996,658,120 (Line 1 + L.ine 2 - Line 3)
System Load 58,052,638 RAM Tab 5, Adj No 1
Production $ per MWH $34.39
PAC-E-08-07
Unbundled Production Revenue Requirement (Excluding Net Power Costs)
Description Amount Source
1 Production - Return On Investment 615,420,689 JAM Tab ECD
2 Production - Expense 3,624,067,686 JAM Tab ECD
3 Production - NPC Expenses (3,224,837,687)RAM Tab 5, Adj No 1
Production Revenue Requirement
(Excluding NPC)1,014,650,688 (Line 1 + Line 2 - Line 3)
System Load 58,052,638 RAM Tab 5, Adi No 1
Production $ per MWH .......... . ..;$17.48
Rocky Mountain Power
Exhibit No. 80 Page.2 of 3
Case No. PAG-E-10-07
Witness: Steven R. McDougal
Idaho Public Utilties Commission Production Request 5
Unbundled Production Revenue Requirement (Excluding NPC)
December 2008 Annual Report
Unbundled Production Revenue Requirement (Excluding Net Power Costs)
Description Amount Source
1 Production - Return On Investment 720,198,369 JAM Tab ECO
2 Production - Expense 2,399,270,653 JAM Tab ECO
3 Production - NPC Expenses (2,018,890,690)RAM Tab 5, Adj No 1
Production Revenue Requirement
(Excluding NPC)1,100,578,332 (Line 1 + Line 2 - Line 3)
System Load 58,587,247 RAM Tab 5, Adi No 1
Production $ per MWH $18.79
December 2007 Annual Report
Unbundled Production Revenue Requirement (Excluding Net Power Costs)
Description Amount Source
1 . Production - Return On Investment 562,886,786 JAM Tab ECO
2 Production - Expense 2,999,195,474 JAM Tab ECO
3 Production - NPC Expenses (2,622,848,200)RAM Tab 5, Adj No 1
Production Revenue Requirement
(Excluding NPC)939,234,060 (Line 1 + Line 2 - Line 3)
System Load 58,070,670 RAM Tab 5, Adi No 1
Production $ per MWH $16.17
December 2006 Annual Report
Unbundled Production Revenue Requirement (Excluding Net Power Costs)
Description Amount Source
1 Production - Return On Investment 502,326,524 JAM Tab ECO
2 Production - Expense 3,236,453,200 JAM Tab ECO
3 Production - NPC Expenses (2,809,578,442)RAM Tab 5, Adj No 1
Production Revenue Requirement
(Excluding NPC)929,201 ,282 (Line 1 + Line 2 - Line 3)
System Load 56,111,183 RAM Tab 5, Adj No 1
Production $ per MWH $16.56
March 2006 Annual Report
Unbundled Production Revenue Requirement (Excluding Net Power Costs)
Description Amount Source
1 Production - Return On Investment 455,964,647 JAM Tab ECO
2 Production - Expense 2,659,321,887 JAM Tab ECO
3 Production - NPC Expenses (2,238,052,891 )RAM Tab 5, Adj No 1
Production Revenue Requirement
(Excluding NPC)877,233,643 (Line 1 + Line 2 - Line 3)
SYStem Load 54,578,830 RAM Tab 5,Adi No 1
Production $ per MWH $16.07
Rocky Mountain Power
Exhibit No. 80 Page 3 of 3
Case No. PAC-E-10-07
Witness: Steven R. McDougal
Idaho Public Utilties Commission Production Request 5
Unbundled Production Revenue Requirement (Excluding NPC)
March 2005 Annual Report
Unbundled Production Revenue Requirement (Excluding Net Power Costs)
Description Amount Source
1 Production - Return On Investment 393,879,072 JAM Tab EGD
2 Production - Expense 2,269,943,097 JAM Tab EGD
3 Production - NPG Expenses (1,848,507,139)RAM Tab 5, Adj No 1
Production Revenue Requirement
(Excluding NPG)815,315,030 (Line 1 + Line 2 - Line 3)
System Load 53,264,625 RAM Tab 5, Adj No 1
Production $ per MWH $15.31