HomeMy WebLinkAbout20040715Taylor Supplemental.pdfBEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
INVESTIGATION OF
INTER-JURISDICTIONAL
ISSUES AFFECTING P ACIFICORP )
DBA UTAH POWER & LIGHT CO. )
CASE NO. P AC-O2-
. SUPPLEMENTAL DIRECT
TESTIMONY OF
DAVID L. T AYLOR
JULY 2004
Are you the same David L. Taylor who offered Direct Testimony in this
proceeding?
Yes.
Purpose
What is the purpose of your Supplemental Direct Testimony in these
proceedings?
My Supplemental Testimony discusses and supports changes to the PacifiCorp
Inter-Jurisdictional Cost Allocation Protocol ("Protocol") contained in Exhibit
No. 19. As in my Direct Testimony, when I capitalize terms in my Supplemental
Testimony, those terms have the same meaning as provided for in Appendix A to
the Revised Protocol contained in Exhibit No. 19.
Specifically, my Supplemental Testimony focuses on the following key
areas:
Proposed changes to classification of SCCTs
Proposed changes to the allocation of Regional Resources
Proposed allocation of Existing QF Contracts,
Proposed elimination of Protocol language related to the allocation of
transmission costs,
Clarification and detail on the treatment of Special Contracts, and
Estimates of the revised Protocol's impact on the revenue requirements of
each State.
Taylor, Sup -
Pacifi Corp
Cost Allocation Appendices
Have you prepared Exhibits that identify how all cost components of the
revenue requirement are allocated among States under the Revised Protocol?
Yes. Exhibit No. 21 , which is Appendix B of the Revised Protocol, identifies the
allocation factor applied to each component of the revenue requirement
calculation. Exhibit No. 22, which is Appendix C of the Revised Protocol, gives a
detailed explanation and the algebraic formula for each allocation factor. Exhibit
No. 23, which is Appendix D of the Revised Protocol, provides a description and
numerical examples of the proposed treatment of Special Contracts. I will discuss
this in detail later in my testimony. Exhibit No. 24, which is Appendix E of the
Revised Protocol, provides the methodology for calculating the Annual
Embedded Cost that I also discuss later in my testimony.
Classification of Simple-Cycle Combustion Turbine Fixed Costs
In your direct testimony, PacifiCorp proposed to classify the fixed costs of
SCCTs differently from the remainder of the Company s Resources. Has the
Company reconsidered this proposal?
Yes. The Company now proposes to classify the Fixed Costs of SCCTs on the
same basis as all other Resources. Although SCCTs are generally designed and
operated to run during peak-load periods, rather than to produce sustained, low
cost energy, we have been persuaded that there are valid reasons to continue past
allocation practices that classify the Fixed Costs of all Resources as 75 percent
Demand-Related and 25 percent Energy-Related.
Taylor, Sup - 2
Pacifi Corp
What are those reasons?
First, as discussed in my Direct Testimony, a wide range of demand and energy
classification methods could be supported on a technical basis. Given the
diversity of PacifiCorp s Resource portfolio, it has been argued that certain
Resources should be classified more heavily to Demand-Related and that certain
Resources should be classified more heavily to Energy-Related. The
classification of all Resources as 75 percent Demand-Related and 25 percent
Energy-Related appears to fairly recognize this balance. To single out one type of
Resource - SCCTs - for special treatment could upset the balance and lead to
unnecessary complexity and ambiguity for classification of all Resources.
Second, the proposed change recognizes that the operation of Resources
on a year-to-year basis varies due to load and market factors and may be different
from the expected operation when the Resources were acquired. Finally, the
Company agrees with several parties that, absent a compelling reason to change,
minimizing changes from current allocation practices will aid in implementation
of the Protocol and limit cost shifts among States.
Does the Company propose to eliminate the Seasonal Resource designation
for allocation of SCCTs and include them as part of System Resources?
No. SCCTs will continue to be treated as Seasonal Resources with their costs
allocated using seasonal allocation factors as described in my Direct Testimony.
Taylor, Sup - 3
PacifiCorp
Cost Allocation for Regional Resources
What changes is the Company proposing to the allocation of Regional
Resources?
As discussed in Ms. Kelly s testimony, the Company proposes to eliminate the
coal endowment and to eliminate the ability for Oregon to opt out of the First
Major New Coal Resource. In addition, the Company proposes a change to the
allocation of costs related to Hydro-Electric Resources, Mid-Columbia Contracts
and Existing QF Contracts.
Hydro- Electric Resources and Mid -Columbia Contracts
Please explain how the costs of Hydro-Electric Resources are assigned and
allocated under the Revised Protocol.
In the Revised Protocol, the existing and future investment and operating costs of
Hydro-Electric Resources are, in the first instance, allocated on a system-wide
basis. Then, the total normalized costs of H ydro- Electric Resources are compared
against the normalized costs of the remaining generation portfolio on a $/MWH
basis a~d an adjustment which reflects the cost difference is applied. This
adjustment is referred to as "The Owned-Hydro Embedded Cost Differential
Adjustment" .
The Owned-Hydro Embedded Cost Differential Adjustment is calculated
as the Annual Embedded Costs - Hydro-Electric Resources, less the Annual
Embedded Costs - All Other, multiplied by the normalized MWh's of output
from the Hydro-Electric Resources used to set rates. The adjustment is then
allocated to former Pacific Power jurisdictions using the DGP factor and the
Taylor, Sup - 4
PacifiCorp
reciprocal amount (All Other less Hydro) will be allocated to all States using the
SO factor. Currently the adjustment is negative (the Hydro-Electric Resource
costs are less expensive than all other Resources), so it is a net credit to the former
Pacific Power jurisdictions and a cost to the other jurisdictions. In the future, the
adjustment is forecasted to become positive (the Hydro-Electric Resource costs
are more expensive than all other Resources). At that time the adjustment would
be a net cost to the former Pacific Power jurisdictions and a credit to the other
jurisdictions.
Mid-Columbia Contracts and Existing QF Contracts
Please explain how the costs of Mid-Columbia Contracts are assigned and
allocated under the Revised Protocol.
Similar to Hydro-Electric Resources, the costs of Mid-Columbia Contracts are, in
the first instance, allocated on a system-wide basis. Then, the total normalized
costs of Mid-Columbia Contracts are compared against normalized costs of the
remaining generation portfolio on a $/MWH basis and an adjustment which
reflects the cost difference is applied. This adjustment is referred to as the "Mid-
Columbia Contracts Cost Differential Adjustment"
The Mid-Columbia Contracts Cost Differential Adjustment is calculated
as the Annual Mid-Columbia Contract Costs, less the Annual Embedded Costs-
All Other, multiplied by the normalized MWh's of output from the Mid-Columbia
Contracts. The adjustment is then allocated to all States using the Mid-Columbia
(MC) factor and the reciprocal amount (All Other less Mid-C) is allocated to all
States using the SG factor.
Taylor, Sup - 5
PacifiCorp
The calculation of the MC factor is shown in Appendix F of the Revised
Protocol and described in detail in Mr. Duvall's Supplemental Direct Testimony.
Please describe how the costs of Existing QF Contracts are assigned and
allocated under the Revised Protocol.
Existing QF Contracts are treated similarly to the Hydro Resources and the Mid-
Columbia Contracts. Like Hydro-Electric Resources, the costs of Mid-Columbia
Contracts are, in the first instance, allocated on a system-wide basis. But then
unlike the Hydro Electric Resource and Mid-Columbia Contract costs, which are
compared to other generation costs at an aggregate level, the Existing QF cost
difference is calculated separately for each State. The Existing QF Contract costs
in each State are compared against normalized costs of the remaining generation
portfolio on a $/MWH basis and an adjustment which reflects the cost difference
is applied. This adjustment is referred to as "Existing QF Contracts Cost
Differential Adjustment"
The Existing QF Contracts Cost Differential Adjustment is calculated as
the Annual Existing QF Contracts Costs for a specific State, less the Annual
Embedded Costs - All Other, multiplied by the normalized MWh's of output
from that State s Existing QF Contracts. This adjustment is situs assigned to that
State. The sum of this adjustment for all States is calculated and an adjustment
for the reciprocal amounts (All Other less Total System QF) is allocated to all
States using the SG factor.
How are the Company s Annual Embedded Costs calculated?
Annual Embedded Costs are calculated for Hydro-Electric Resources, Mid-
Taylor, Sup - 6
PacifiCorp
Columbia Contracts, Existing QF Contracts, and all other Resources. They are
based on fully normalized test period costs captured in the FERC accounts
identified in Appendix E to the Revised Protocol, Exhibit No. 24.
As shown on lines 1 through 11 of Appendix E, the Annual Embedded
Costs - Hydro-Electric Resources include the identified hydro-related operation
and maintenance, depreciation, and amortization expenses plus the identified
hydro- related rate base items times the pre-tax authorized (or requested) return on
rate base, $70,969,571 in this example. This amount is divided by the annual
hydro MWh, from the GRID run used in the test period net power cost
calculation, 4 128 973 MWh, to arrive at the Annual Embedded Costs - Hydro-
Electric Resources of $17.19 per MWh.
The Annual Costs, MWh, and corresponding cost per MWh are shown for
Mid-Columbia Contracts and total Existing QF Contracts on lines 12 and 13,
respecti vel y.
The Annual Embedded Costs - All Other are shown on lines 14 through
44. This calculation is similar to the costs for Hydro-Electric Resources described
above and results in Annual Embedded Costs - All Other of $32.00 per MWh.
This is the cost to which Annual Embedded Costs - Hydro-Electric, Annual Mid-
Columbia Contract Costs, and Annual Existing QF Costs are compared.
Did the Company evaluate alternatives to the Embedded Cost Differential as
a form of Hydro Endowment?
Yes. The following three alternatives to the Embedded Cost Differential were
proposed and evaluated in the course of the MSP:
Taylor, Sup - 7
PacifiCorp
Combining the Hydro Endowment with a Coal Endowment,
Using or modifying the fuel adjustment mechanism, and
Reinstating a load decrement approach.
I will discuss the reasons for the rejection of these approaches in favor of the
embedded cost differential"
Why did the Company abandon its proposal to combine the Hydro
Endowment with a Coal Endowment, as described in your direct testimony?
It did not enjoy support from MSP participants.
Please describe the existing "fuel adjustment mechanism
The fuel adjustment mechanism that is part of the Modified Accord allocation
methodology:
Calculates the difference (on a $/MWH basis) between the 5-year average
of the O&M Expenses of the Company s Hydro-Electric Resources and
the O&M Expenses of the Company s Thermal Resources;
Multiplies the $/MWH difference by the MWHs of generation from
Hydro-Electric Resources, and then allocates the difference as a credit to
the former Pacific Power jurisdictions and as a charge to all jurisdictions;
and
Allocates the costs of post -1989 capital investments across the system
based on each State s proportional load in a test period.
A corresponding calculation is also calculated for the former Utah Power Hydro-
Electric Resources.
Taylor, Sup - 8
Pacifi Corp
Please discuss the drawbacks of the existing fuel adjustment mechanism.
One primary drawback is that the mechanism compares only the operating costs
of thermal Resources and the operating costs of Hydro-Electric Resources and
therefore does not account for the Fixed Costs of either type of Resource. Another
problem is that it does not equitably match the distribution of the benefits of
Hydro-Electric Resources with the responsibility for the expected substantial
increase in capital costs for the relicensing and other capital investments
associated with Hydro-Electric Resources. That is to say, under Modified
Accord, all States bear a proportionate share of post Utah/Pacific merger Hydro-
Electric Resource capital costs, but only former Pacific Power States receive the
fuel cost advantage of Hydro-Electric Resources.
Did parties consider options that would address these inequities?
Yes. Parties evaluated a short-term fuel adjustment mechanism that phased out as
the revenue requirement of relicensing costs exceeded the fuel benefits.
However, this approach did not eliminate the inequities. This mechanism
incorporated a mismatch of costs in that it involved a comparison of both the
Fixed Costs and Variable Costs of Hydro-Electric Resources against only the
Variable Costs of thermal Resources. Again, some States received credits for fuel
benefits for the next several years but all States bore the risk of the costs of
relicensing. Additionally, this approach was rejected by some parties because it
was not permanent.
Please describe the "load decrement approach"
Under the load decrement approach, the costs of H ydro- Electric Resources are
Taylor, Sup - 9
PacifiCorp
assigned to and allocated among the former Pacific Power jurisdictions. At the
same time, the loads of the former Pacific Power jurisdictions are reduced by the
output of the Hydro-Electric Resources, prior to the development of allocation
factors for the remaining System Resources. This reduces the Pacific Power
jurisdictions' allocated share of the cost of the remaining System Resources. This
type of approach was utilized under the Accord Method from 1993 to 1997.
Why isn t the Company proposing to reinstate the load decrement approach?
Our studies have revealed drawbacks to this mechanism. Most significantly, the
load growth studies revealed that the load decrement approach distorts the
allocation of costs associated with load growth to the States with decremented
loads. Not only are States with decremented loads allocated a smaller share of
existing remaining System Resources, they are also allocated a smaller share of
the cost of new System Resources. This is in conflict with the principle that
States should pay for the costs of their load growth to the maximum extent
possible.
Transmission Costs
How has the Company revised the Protocol in respect to the classification
and allocation of transmission costs?
In its initial proposal, PacifiCorp included an allocation provision that would have
applied should Commissions approve its participation in a Regional Transmission
Organization ("RTO"). The proposal was simply to allocate charges from the
RTO among the States based upon the same billing determinants relied upon by
the FERC in setting the RTO's rates. Several parties expressed concern that this
Taylor, Sup - 10
Pacifi Corp
proposal was premature given the evolving regional RTO discussions and
requested that the provision be eliminated. The Company has complied with
those requests and removed that provision.
Special Contracts
Has the Company modified its proposal regarding the treatment of Special
Contracts?
No. However Appendix D, Exhibit No. 23, has been added to the Protocol for
greater clarity. Appendix D identifies two general types of Special Contracts: 1)
Special Contracts without Customer Ancillary Service Contract attributes and 2)
Special Contracts with Customer Ancillary Service Contract attributes. For both
types of Special Contracts , the cost of serving contract customer loads, and their
State-approved retail service revenues, will be included in the local State
revenue requirement. However, the regulatory treatment of the two types of
Special Contracts is different. Let me explain the difference.
For allocation purposes Special Contracts without Customer Ancillary
Service Contract attributes are viewed as one transaction and the system benefits
and load reductions accruing from customer interruptions are treated very
similarly to DSM. Like DSM, the host jurisdiction benefits from the reduction in
system costs through smaller allocation of total system costs. Specifically, loads
of Special Contract customers will be included in all Load-Based Dynamic
Allocation Factors. When interruptions of a Special Contract customer s service
occur, the reduction in load will be reflected in the host jurisdiction s Load-Based
Dynamic Allocation Factors. Actual revenues received from a Special Contract
Taylor, Sup -
Pacifi Corp
customer will be assigned to the State where the Special Contract customer is
located. A numeric example of the regulatory treatment of Special Contracts
without Ancillary Service Contract attributed is shown in Appendix D, Table
For allocation purposes Special Contracts with Customer Ancillary
Service Contract attributes are viewed as two transactions. PacifiCorp sells the
customer electricity at the retail service rate and then buys the electricity back
during the interruption period at the ancillary service contract rate. Loads
associated with the retail service to the Special Contract customers will be
included in all Load-Based Dynamic Allocation Factors. The Customer Ancillary
Service Contract attributes of the Special Contract are viewed, not as a reduction
in load, but rather as the acquisition of Resources to meet Company load.
Therefore, when interruptions of a Special Contract customer s service occur, the
host jurisdiction s Load-Based Dynamic Allocation Factors and the retail service
revenue are calculated as though the interruption did not occur. Revenues
received from Special Contract customer, before any discounts for Customer
Ancillary Service Contract attributes of the Special Contract, will be assigned to
the State where the Special Contract customer is located. Because discounts from
tariff prices provided for in Special Contracts or payments to retail customers, that
recognize the Customer Ancillary Service Contract attributes of the Contract are
considered as payments for Resource acquisitions, they will be allocated among
States on the same basis as System Resources. A numeric example of the
regulatory treatment of Special Contracts with Customer Ancillary Service
Contract attributes is shown in Appendix D, Table 2.
Taylor, Sup - 12
PacifiCorp
When a buy-through option is provided with economic curtailment, the
load, costs and revenue associated with a customer buying through economic
curtailment will be excluded from the calculation of State revenue requirements.
The cost associated with the buy- through will be removed from the calculation of
net power costs, the Special Contract customer load associated with the buy-
through will be not be included in the calculation of Load-Based Dynamic
Allocation Factors, and the revenue associated with the buy- through will not be
included in State revenues.
Revenue Requirement Impacts
Have you prepared an exhibit showing the impact of the Revised Protocol on
revenue requirements?
Yes. Exhibit No. 25 presents estimates of impacts on each State s revenue
requirement. Estimated revenue requirements for California, Oregon,
Washington, and Wyoming are compared to the Modified Accord methodology.
Estimated revenue requirements for Idaho and Utah are compared to the Rolled-
methodology. A positive percent indicates the State s revenue requirement for a
given year under the MSP Solution is higher and a negative percent indicates the
revenue requirement under the MSP Solution is lower. The year-by-year revenue
requirement impacts are shown for the period 2005 thorough 2018 as well as the
Net Present Value of the difference in revenue requirements over the 14-year
period. For each State, the percent change in revenue requirement associated with
the effect of moving from Modified Accord to Rolled-In (if applicable), the
Hydro Endowment (both Company Owned and Mid-C components), Existing QF
Taylor, Sup - 13
Pacifi Corp
Contracts and Seasonal Resources is shown first followed by the impact of the
full MSP Solution.
What are the important analytical assumptions underlying these
calculations?
They include projections of Hydro-Electric Resource relicensing costs, expected
new Resources as reflected in the Company s 2003 IRP, clean air investments and
a carbon tax commencing in 2008.
What factors are not reflected in the calculations?
The calculations do not include the potential State-by-State revenue requirement
impacts of New QF Contracts, Special Contracts and Portfolio Resources.
What do you conclude from Exhibit No. 25?
I conclude that the revenue requirement impacts are within an acceptable range.
While the Revised Protocol produces somewhat lower revenue requirements for
Oregon, Washington, and Wyoming in the early years, the trend reverses and
those States see larger revenue requirements in the later years. The higher
Revised Protocol revenue requirements seen by Utah and Idaho in the early years
are offset by lower revenue requirements in the later years.
Does this conclude your Supplemental Direct Testimony?
Yes.
Taylor, Sup - 14
Pacifi Corp
~:;,
Case No. P AC-O2-
Exhibit No. 21
Witness: David L. Taylor
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ACIFICORP
Exhibit AccompanYing Supplemental Direct Testimony of David L. Taylor
Appendix B - Allocation Factor Applied to each Component of Revenue Requirement
July 2004
PacifiCorp
Exhibit No. 21 Page lof21
Protocol Appendix B .Case No. ~AC-O2-
ess: DavId L. TaylorAllocation Factor Applied to each Component of Revenue Requlremen
FERC
ACCT
Sales to Ultimate Customers440 Residential Sales
DESCRIPTION
ALLOCATION
FACTOR
Direct assigned - Jurisdiction
442 Commercial & Industrial Sales
Direct assigned - Jurisdiction
444 Public Street & Highway Lighting
Direct assigned - Jurisdiction
445 Other Sales to Public Authority
Direct assigned. Jurisdiction
448 Interdepartmental
Direct assigned - Jurisdiction
447 Sales for Resale
Direct assigned - Jurisdiction
Non-Firm
Firm
449 Provision for Rate Refund
Direct assigned - Jurisdiction
Other Electric Operating Revenues450 Forfeited Discounts & Interest
Direct assigned - Jurisdiction
451 Misc Electric Revenue
Direct assigned - Jurisdiction
Other - Common
454 Rent of Electric Property
Direct assigned - Jurisdiction
Common
PacifiCorp
Exhibit No. 21 Page 2 of 21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-O2-
Witness: David L. Taylor
FERC
ACCT DESCRIPTION
AllOCATION
FACTOR
456 Other Electric Revenue
Direct assigned - Jurisdiction
Wheeling Non-firm, Other
Common
Wheeling - Firm, Other
Miscellaneous Revenues
41160 Gain on Sale of Utility Plant - CR
Direct assigned - Jurisdiction
Production, Transmission
General Office
41170 loss on Sale of Utility Plant
Direct assigned - Jurisdiction
Production, Transmission
General Office
4118 Gain from Emission Allowances
S02 Emission Allowance sales
41181 Gain from Disposition of NOX Credits
NOX Emission Allowance sales
421 (Gain) floss on Sale of Utility Plant
Direct assigned - Jurisdiction
Production, Transmission
General Office
Miscellaneous Expenses4311 Interest on Customer Deposits
Utah Customer Service Deposits
PacifiCorp
Exhibit No. 21 Page 3 of 21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-O2-
Witness: David L. Taylor
FERC
ACCT
Steam Power Generation
DESCRIPTION
ALLOCATION
FACTOR
500, 502, 504-514 Operation Supervision & Engineering
Remaining Steam Plants
Peaking Plants
Cholla
SSGCT
SSGCH
501 Fuel Related
Remaining steam plants
Peaking Plants
Chona
SSECT
SSECH
503 Steam From Other Sources
Steam Royalties
Nuclear Power Generation
517 - 532 Nuclear Power O&M
Nuclear Plants
Hydraulic Power Generation
535 - 545 Hydro O&M
Pacific Hydro
East Hydro
Other Power Generation
546, 548-554 Operation Super & Engineering
Other Production Plant
547 Fuel
Other Fuel Expense
PacifiCorp
Exhibit No. 21 Page 4 of21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-O2-
Witness: David L. Taylor
FERC
ACCT
Other Power Supply
555
556 - 557
DESCRIPTION
Purchased Power
Direct assigned - Jurisdiction
Firm
Non-firm
1 00 MW Hydro Extension
Peaking Contracts
System Control & Load Dispatch
Other Expenses
Embedded Cost Differential Endowments
Company Owned Hydro Embedded Cost Differential (Hydro less All Other)
Company Owned Hydro Embedded Cost Differential (All Other less Hydro)
Mid-Columbia Contract Embedded Cost Differential (Mid C less All Other)
Mid-Columbia Contract Embedded Cost Differential (All Other less Mid C)
Existing OF Contracts Embedded Cost Differential (OF less- All Other)
Existing OF Contracts Embedded Cost Differential (All Other less OF)
TRANSMISSION EXPENSE
560-564, 566-573 Transmission O&M
565
Transmission Plant
Transmission of Electricity by Others
Firm Wheeling
Non-Firm Wheeling
DISTRIBUTION EXPENSE580 - 598 Distribution O&M
Direct assigned - Jurisdiction
Other Distribution
CUSTOMER ACCOUNTS EXPENSE901 - 905 Customer Accounts O&M
Direct assigned - Jurisdiction
Total System Customer Related
CUSTOMER SERVICE EXPENSE907 - 910 Customer Service O&M
Direct assigned - Jurisdiction
Total System Customer Related
SALES EXPENSE
911-916 Sales Expense O&M
Direct assigned - Jurisdiction
Total System Customer Related
ALLOCATION
FACTOR
SSGC
DGP
SNPD
PacifiCorp
Exhibit No. 21 Page 5 of 21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-E-O2-
Witness: David L. Taylor
FERC
ACCT DESCRIPTION
ALLOCATION
FACTOR
ADMINISTRATIVE & GEN EXPENSE920-935 Administrative & General Expense
Direct assigned - Jurisdiction
Customer Related
General
FERC Regulatory Expense
DEPRECIATION EXPENSE403SP Steam Depreciation
Remaining Steam Plants
Peaking Plants
Cholla
SSGCT
SSGCH
403NP Nuclear Depreciation
Nuclear Plant
403HP Hydro Depreciation
Pacific Hydro
East Hydro
4030P Other Production Depreciation
Other Production Plant
403TP Transmission Depreciation
Transmission Plant
403 Distribution Depreciation Direct assigned - Jurisdiction
Land & Land Rights
Structures
Station Equipment
Poles & Towers
OH Conductors
UG Conduit
UG Conductor
Line Trans
Services
Meters
Inst Cust Prem
Leased Property
Street Lighting
PacifiCorp
Exhibit No. 21 Page 6 of21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-O2-
Witness: David L. Taylor
FERC
ACCT DESCRIPTION
ALLOCATION
FACTOR
403GP General Depreciation
Distribution
Remaining Steam Plants
Peaking Plants
Cholla
Customer Related
General SO
SSGCT
SSGCH
Pacific Hydro
East Hydro
Transmission
403MP Mining Depreciation
Remaining Mining Plant
AMORTIZATION EXPENSE404GP Amort of L T Plant - Capital Lease Gen
Direct assigned - Jurisdiction
General
Customer Related
404SP Amort of L T Plant - Cap Lease Steam
Steam Production Plant
4041P Amort of L T Plant - Intangible Plant
Distribution
Production, Transmission
General
Mining Plant
Customer Related
404MP Amort of L T Plant - Mining Plant
Mining Plant
404HP Amortization of Other Electric Plant
Pacific Hydro
East Hydro
405 Amortization of Other Electric Plant
Direct assigned - Jurisdiction
PacifiCorp
Exhibit No. 21 Page 7 of 21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-E-O2-
Witness: David L. Taylor
FERC
ACCT DESCRIPTION
ALLOCATION
FACTOR
406 Amortization of Plant Acquisition Adj
Direct assigned - Jurisdiction
Production Plant
407 Amort of Prop Losses, Unrec Plant, etc
Direct assigned - Jurisdiction
Production, Transmission
Trojan TROJP
Taxes Other Than Income
408 Taxes Other Than Income
Direct assigned - Jurisdiction
Property
General Payroll Taxes
Misc Energy
Misc Production
GPS
DEFERRED ITC
41140 Deferred Investment Tax Credit - Fed
ITC DGU
41141 Deferred Investment Tax Credit - Idaho
ITC DGU
Interest Expense
427 Interest on Long-Term Debt
Direct assigned - Jurisdiction
Interest Expense SNP
428 Amortization of Debt Disc & Exp
Interest Expense SNP
429 Amortization of Premium on Debt
Interest Expense SNP
431 Other Interest Expense
Interest Expense SNP
432 AFUDC - Borrowed
AFUDC SNP
PacifiCorp
Exhibit No. 21 Page 8 of 21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-E-O2-
Witness: David L. Taylor
FERC
ACCT DESCRIPTION
ALLOCATION
FACTOR
Interest & Dividends
419 Interest & Dividends
Interest & Dividends SNP
DEFERRED INCOME TAXES41010 Deferred Income Tax - Federal-
Direct assigned - Jurisdiction
Electric Plant in Service
Pacific Hydro
Production, Transmission
Customer Related
DITEXP
GPS
SNP
TROJP
SNPD
General
Property Tax related
Miscellaneous
Trojan
Distribution
Mining Plant
41011 Deferred Income Tax - State-
Direct assigned - Jurisdiction
Electric Plant in Service
Pacific Hydro
Production, Transmission
Customer Related
DITEXP
GPS
SNP
TROJP
SNPD
General
Property Tax related
Miscellaneous
Trojan
Distribution
Mining Plant
41110 Deferred Income Tax . Federal-
Direct assigned - Jurisdiction
Electric Plant in Service
Pacific Hydro
Production, Transmission
Customer Related
General
Property Tax related
Miscellaneous
DITEXP
GPS
SNP
TROJP
SNPD
Trojan
Distribution
Mining Plant
PacifiCorp
Exhibit No. 21 Page 9 of 21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-E-O2-
Witness: David L. Taylor
FERC
ACCT DESCRIPTION
ALLOCATION
FACTOR
41111 Deferred Income Tax - State-
Direct assigned - Jurisdiction
Electric Plant in Service
Pacific Hydro
Production, Transmission
Customer Related
DITEXP
GPS
SNP
TROJP
SNPD
General
Property Tax related
Miscellaneous
Trojan
Distribution
Mining Plant
SCHEDULE - M ADDITIONSSCHMAF Additions - Flow Through
Direct assigned - Jurisdiction
SCHMAP Additions - Pennanent
Mining related
General
SCHMAT Additions - Temporary
Direct assigned - Jurisdiction
Contributions in aid of construction
Miscellaneous
Depreciation
CIAC
SNP
TROJP
GPS
SCHMDEXP
Trojan
Pacific Hydro
Mining Plant
Production, Transmission
Property Tax
General
PacifiCorp
Exhibit No. 21 Page 10 of 21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-O2-
Witness: David L. Taylor
FERC
ACCT
SCHEDULE - M DEDUCTIONSSCHMDF Deductions - Flow Through
Direct assigned - Jurisdiction
Production, Transmission
Pacific Hydro
DESCRIPTION
ALLOCATION
FACTOR
SCHMDP Deductions - Permanent
Direct assigned - Jurisdiction
Mining Related
Miscellaneous
General
SNP
SCHMDT Deductions - Temporary
Direct assigned - Jurisdiction
Bad Debt
Miscellaneous
Pacific Hydro
Mining related
Production, Transmission
BADDEBT
SNP
GPS
TAXDEPR
SNPD
Property Tax
General
Depreciation
Distribution
State Income Taxes
40911 State Income Taxes
Income Before Taxes IBT
40910
40910
FIT True-up
Wyoming Wind Tax Credit
Steam Production Plant
310 - 316
Remaining Steam Plants
Peaking Plants
Cholla
SSGCT
SSGCH
Nuclear Production Plant
320-325
Nuclear Plant
PacifiCorp
Exhibit No. 21 Page 11 of21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-E-O2-
Witness: David L. Taylor
FERC
ACCT
Hydraulic Plant
330-336
DESCRIPTION
ALLOCATION
FACTOR
Pacific Hydro
East Hydro
Other Production Plant
340-346
Other Production Plant
TRANSMISSION PLANT
350-359
Transmission Plant
DISTRIBUTION PLANT
360-373
Direct assigned - Jurisdiction
PacifiCorp
Exhibit No. 21 Page 120f21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-O2-
Witness: David L. Taylor
FERC
ACCT
GENERAL PLANT
389 - 398
DESCRIPTION
ALLOCATION
FACTOR
Distribution
Remaining Steam Plants
Peaking Plants
Cholla
SSGCT
SSGCH
Pacific Hydro
East Hydro
Transmission
Customer Related
General SO
399 Coal Mine
Remaining Mining Plant
399L WIDCO Capital Lease
WIDCO Capital Lease
1011390 General Capital Leases
Direct assigned. Jurisdiction
General
Unclassified Gen Plant - Acct 300
Distribution
Customer Related
General
SSGCT
SSGCH
Remaining Steam Plants
Peaking Plants
Cholla
Pacific Hydro
East Hydro
Transmission
PacifiCorp
Exhibit No. 21 Page 13 of 21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-O2-
Witness: David L. Taylor
FERC
ACCT
INTANGIBLE PLANT
301
DESCRIPTION
ALLOCATION
FACTOR
Organization
Direct assigned - Jurisdiction
302 Franchise & Consent
Direct assigned,- Jurisdiction
Production, Transmission
303 Miscellaneous Intangible Plant
Distribution
Remaining Steam Plants
Peaking Plants
Cholla
Customer Related
General
SSGCT
SSGCH
Pacific Hydro
East Hydro
Transmission
303 Less Non-Utility Plant
Direct assigned - Jurisdiction
PacifiCorp
Exhibit No. 21 Page 14 of 21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-O2-
Witness: David L. Taylor
FERC
ACCT
Rate Base Additions
105
114
115
120
124
182W
186W
151
152
25316
25317
25319
DESCRIPTION
ALLOCATION
FACTOR
Plant Held For Future Use
Direct assigned - Jurisdiction
Production, Transmission
Mining Plant
Electric Plant Acquisition Adjustments
Direct assigned - Jurisdiction
Production Plant
Accum Provision for Asset Acquisition Adjustments
Direct assigned - Jurisdiction
Production Plant
Nuclear Fuel
Nuclear Fuel
Weatherization
Direct assigned - Jurisdiction
General
Weatherization
Direct assigned - Jurisdiction
Weatherization
Direct assigned - Jurisdiction
Fuel Stock
Steam Production Plant
Fuel Stock - Undistributed
Steam Production Plant
DG&T Working Capital Deposit
Mining Plant
DG&T Working Capital Deposit
Mining Plant
Provo Working Capital Deposit
Mining Plant
PacifiCorp
Exhibit No. 21 Page 15 of 21
Allocation Factor Applied to each Component of Revenue RequiremenfaseNo. PAC-O2-
Witness: David L. Taylor
FERC
ACCT
ALLOCATION
FACTORDESCRIPTION
154 Materials and Supplies
Direct assigned - Jurisdiction
Production, Transmission
Mining
General
SNPPS
SNPPH
SNPD
Production - Common
Hydro
Distribution
163 Stores Expense Undistributed
General
25318 Provo Working Capital Deposit
Provo Working Capital Deposit SNPPS
165 Prepayments
Direct assigned - Jurisdiction
Property Tax
Production, Transmission
Mining
General
GPS
182M Misc Regulatory Assets
Direct assigned - Jurisdiction
Production, Transmission
Cholla Transaction Costs
Mining
General
SSGCH
186M Misc Deferred Debits
Direct assigned - Jurisdiction
Production, Transmission
General
Mining
Production - Common SNPPS
PacifiCorp
Exhibit No. 21 Page 16 of21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-O2-
Witness: David L. Taylor
FERC
ACCT
Working Capital
CWC
DESCRIPTION
ALLOCATION
FACTOR
Cash Working Capital
Direct assigned - Jurisdiction
OWC
131
135
143
232
232
253
25330
Other Working Capital
Cash
Working Funds
Other Accounts Receivable
Accounts Payable
Accounts Payable
Deferred Hedge
Other Deferred Credits - Misc
SNP
Miscellaneous Rate Base
18221 Unrec Plant & Reg Study Costs
Direct assigned - Jurisdiction
18222 Nuclear Plant - Trojan
Trojan Plant
Trojan Plant
TROJP
TROJD
141 Impact Housing - Notes Receivable
Employee Loans - Hunter Plant
PacifiCorp
Exhibit No. 21 Page 17 of 21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-O2-
Witness: David L. Taylor
FERC
ACCT
Rate Base Deductions
235
2281
2282
2283
22841
22842
252
25399
190
281
DESCRIPTION
ALLOCATION
FACTOR
Customer Service Deposits
Direct assigned - Jurisdiction
Prov for Property Insurance
Prov for Injuries & Damages
Prov for Pensions and Benefits
Accum Misc Oper Prov.Black Lung
Mining
Accum Misc Oper Prov-Trojan
Trojan Plant TROJD
Customer Advances for Construction
Direct assigned - Jurisdiction
Production, Transmission
Customer Related
Other Deferred Credits
Direct assigned - Jurisdiction
Production, Transmission
Mining
Accumulated Deferred Income Taxes
Direct assigned - Jurisdiction
Bad Debt BADDEBT
8NP
TROJP
Pacific Hydro
Production, Transmission
Customer Related
General
Miscellaneous
Trojan
Accumulated Deferred Income Taxes
Production, Transmission
PacifiCorp
Exhibit No. 21 Page 18 of 21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-O2-
Witness: David L. Taylor
FERC
ACCT
ALLOCATION
FACTORDESCRIPTION
282 Accumulated Deferred Income Taxes
Direct assigned - Jurisdiction
Depreciation
Hydro Pacific
Production, Transmission
DITBAL
SNP
TROJP
Customer Related
General
Miscellaneous
Trojan
283 Accumulated Deferred Income Taxes
Direct assigned - Jurisdiction
Depreciation
Hydro Pacific
DITBAL
SNP
TROJP
Production, Transmission
Customer Related
General
Miscellaneous
Trojan
255 Accumulated Investment Tax Credit
Direct assigned - Jurisdiction
Investment Tax Credits ITC84
(TC85
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ITC88
ITC89
ITC90
DGU
Investment Tax Credits
Investment Tax Credits
Investment Tax Credits
Investment Tax Credits
Investment Tax Credits
Investment Tax Credits
PacifiCorp
Exhibit No. 21 Page 19 of21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-O2-
Witness: David L. Taylor
FERC
ACCT
PRODUCTION PLANT ACCUM DEPRECIATION108SP Steam Prod Plant Accumulated Depr
Remaining Steam Plants
Peaking Plants
Chona
DESCRIPTION
ALLOCATION
FACTOR
SSGCT
SSGCH
108NP Nuclear Prod Plant Accumulated Depr
Nuclear Plant
108HP Hydraulic Prod Plant Accum Depr
Pacific Hydro
East Hydro
1080P Other Production Plant - Accum Depr
Other Production Plant
TRANS PLANT ACCUM DEPR108TP Transmission Plant Accumulated Depr
Transmission Plant
DISTRIBUTION PLANT ACCUM DEPR
108360 - 108373 Distribution Plant Accumulated Depr
Direct assigned - Jurisdiction
108DOO Unclassified Dist Plant - Acct 300
Direct assigned - Jurisdiction
108DS Unclassified Dist Sub Plant - Acct 300
Direct assigned - Jurisdiction
108DP Unclassified Dist Sub Plant - Acct 300
Direct assigned - Jurisdiction
PacifiCorp
Exhibit No. 21 Page 20 of21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-02-
Witness: David L. Taylor
FERC
ACCT
GENERAL PLANT ACCUM DEPR108GP General Plant Accumulated Depr
Distribution
Remaining Steam Plants
Peaking Plants
Cholla
DESCRIPTION
ALLOCATION
FACTOR
Customer Related
General SO
SSGCT
SSGCH
Pacific Hydro
East Hydro
Transmission
108MP Mining Plant Accumulated Depr.
Mining Plant
108MP Less Centralia Situs Depreciation
Direct assigned - Jurisdiction
1081390 Accum Depr - Capital Lease
General
1081399 Accum Depr. Capital Lease
Direct assigned - Jurisdiction
PacifiCorp
Exhibit No. 21 Page 21 of21
Allocation Factor Applied to each Component of Revenue Requiremenfase No. PAC-02-
Witness: David L. Taylor
FERC
ACCT
ACCUM PROVISION FOR AMORTIZATION111 SP Accum Prov for Amort-Steam
Remaining Steam Plants
Peaking Plants
Cholla
DESCRIPTION
ALLOCATION
FACTOR
SSGCT
SSGCH
111GP Accum Prov for Amort-General
Distribution
Remaining Steam Plants
Peaking Plants
Cholla
Pacific Hydro
East Hydro
SSGCT
SSGCH
Transmission
Customer Related
General SO
111HP Accum Prov for Amort-Hydro
Pacific Hydro
East Hydro
1111P Accum Prov for Amort-Intangible Plant
Distribution
Pacific Hydro
Production, Transmission
General
Mining
Customer Related
1111P Less Non-Utility Plant
Direct assigned - Jurisdiction
111399 Accum Prov for Amort-Mining
Mining Plant
Case No. PAC-02-
Exhibit No. 22
Witness: David L. Taylor
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ACIFICORP
Exhibit Accompanying Supplemental Direct Testimony of David L. Taylor
Appendix C - Allocation Factor - Algebraic Definitions
July 2004
PacifiCorp
Exhibit No. 22 Page 1 of 18
Docket No. P AC-E-O2-
Witness: David L. Taylor
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Case No. P AC-02-
Exhibit No. 23
Witness: David L. Taylor
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ACIFICORP
Exhibit AccompanYing Supplemental Direct Testimony of David L. Taylor
Appendix D - Special Contracts
July 2004
PacifiCorp
Exhibit No. 23 Page 1 of 3
Case No. PAC-O2-
Witness: David L. Taylor
Protocol Appendix D
Special Contracts
Special Contracts without Ancillary Service Contract Attributes
For allocation purposes Special Contracts without identifiable Ancillary Service Contract attributes are
viewed as one transaction.
Loads of Special Contract customers will be included in all Load-Based Dynamic Allocation Factors.
When inteITUptions of a Special Contract customer s service occur, the reduction in load will be reflected in
the host jurisdiction s Load-Based Dynamic Allocation Factors.
Actual revenues received from Special Contract customer will be assigned to the State where the Special
Contract customer is located.
See example in Table
Special Contracts with Ancillary Service Contract Attributes
For allocation purposes Special Contracts with Ancillary Service Contract attributes are viewed as two
transactions. PacifiCorp sells the customer electricity at the retail service rate and then buys the electricity
back during the interruption period at the Ancillary Service Contract rate.
Loads of Special Contract customers will be included in all Load-Based Dynamic Allocation Factors.
When interruptions of a Special Contract customer s service occur, the host jurisdiction s Load-Based
Dynamic Allocation Factors and the retail service revenue are calculated as though the interruption did not
occur.
Revenues received from Special Contract customer, before any discounts for Customer Ancillary Service
attributes of the Special Contract, will be assigned to the State where the Special Contract customer is
located.
Discounts from tariff prices provided for in Special Contracts that recognize the Customer Ancillary
Service Contract attributes of the Contract, and payments to retail customers for Customer Ancillary
Services will be allocated among States on the same basis as System Resources.
See example in Table 2
Buy-through of Economic Curtailment.
When a buy-through option is provided with economic curtailment, the load, costs and revenue associated
with a customer buying through economic curtailment will be excluded from the calculation of State
revenue requirements. The cost associated with the buy-through will be removed from the calculation of
net power costs, the Special Contract customer load associated with the buy-through will be not be included
in the calculation of Load-Based Dynamic Allocation Factors, and the revenue associated with the buy-
through will not be included in State revenues.
Protocol Appendix D - Table 1
Interruptible Contract Without Ancillary Service Contract Attributes
Effect on Revenue Requirement
2 Jurisdictional Loads - No Interruptible Service
3 Jurisdictional Sum of 12 monthly CP demand (MW)
4 Jurisdictional Annual Energy (MWh)
6 Jurisdictional Loads - With Interruptible Service - Reflecting Actual Interruptions
7 Jurisdictional Sum of 12 monthly CP demand (MW)
8 Jurisdictional Annual Energy (MWh)
10 Special Contract Customer Revenue and Load - Non Interruptible Service
11 Special Contract Customer Revenue
12 Special Contract Customer Sum of 12 CPs (MW) (Included in line 2)
13 Special Contract Annual Energy (MWh) (Included in line 3)
15 Special Contract Customer Revenue and Load - With Interruptible Service (75 MW X 500 Hours of Interruption)16 Special Contract Customer Revenue $ 16,000,000
17 Discount for Ancillary Services
18 Net Cost to Special Contract Customer
19 Special Contract Sum of 12 CP- Reflecting Actual Interruptions (MW) (Included in line 7)
20 Special Contract Annual Energy- Reflecting Actual Interruptions (MWh) (Included in line 8)
22 System Cost Savings from Interruption
24 Allocation Factors
25 No Interruptible Service
26 SE factor (Calculated from line 4)
27 SC factor (Calculated from line 3)
28 SG factor (line 27*75% + line 26*25%)
30 With Interruptible Service (Reflecting Actual Physical Interruptions)
31 SE factor (Calculated from line 8)
32 SC factor (Calculated from line 7)
33 SG factor (line 32*75% + line 31 *25%)
38 Cost of Service
39 Energy Cost
40 Demand Related Costs
41 Sum of Cost
43 Revenues
44 Special Contract Revenue
45 Revenues from all other customers
50 Cost of Service
51 Energy Cost
52 Demand Related Costs
53 Sum of Cost
55 Revenues
56 Special Contract Revenue
57 Revenues from all other customers
Factor
SE1
SC1
SG1
SE2
SC2
SG2
No Interruptible Service
SE1
SG1
Situs $
Situs $
Total system
72,000
42,000,000
71,700
41,962,500
20,000,000
900
500,000
16,000,000
600
462,500
$4,000,000
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
500,000,000 $
000,000,000 $
500,000,000 $
20,000,000
480,000,000 $
With Interruptible Service
SE2
SG2
Situs $
Situs $
498,000,000 $
998,000,000 $
496,000,000 $
16,000,000
480,000,000 $
Jurisdiction 1
24,000
000,000
000
000,000
Jurisdiction 2
36,000
21,000,000
700
20,962 500
20,000,000
900
500,000
PacifiCorp
Exhibit No. 23 Page 2 of 3
Case No. PAC-E-O3-
Witness: David L. Taylor
Jurisdiction 3
12,000
000,000
000
000,000
33.33%50.00%16.67%
33.33%50.00%16.67%
33.33%50.00%16.67%
33.36%49.96%16.68%
33.47%49.79%16.74%
33.45%49.83%16.72%
166,666,667 $
333,333,333 $
500,000,000 $
500,000,000 $
166,148,347 $
334,058,577 $
500,206,924 $
500,206,924 $
16,000,000
000,000
600
462,500
250,000,000 $
500,000,000 $
750,000,000 $
20,000,000
730,000,000 $
248,777,480 $
496,912,134 $
745,689,614 $
16,000,000
729,689,614 $
83,333,333
166,666,667
250,000,000
250,000,000
83,074 173
167 029,289
250,103,462
250,103,462
Protocol Appendix D - Table 2
Interruptible Contract With Ancillary Service Contract Attributes
Effect on Revenue Requirement
2 Jurisdictional Loads - No Interruptible Service
3 Jurisdictional Sum of 12 monthly CP demand (MW)
4 Jurisdictional Annual Energy (MWh)
6 Jurisdictional Loads - With Interruptible Service - Reflecting Actual Interruptions
7 Jurisdictional Sum of 12 monthly CP demand (MW)
8 Jurisdictional Annual Energy (MWh)
10 Special Contract Customer Revenue and Load - Non Interruptible Service
11 Special Contract Customer Revenue
12 Special Contract Customer Sum of 12 CPs (MW) (Included in line 2)
13 Special Contract Annual Energy (MWh) (Included in line 3)
15 Special Contract Customer Revenue and Load - With Interruptible Service (75 MW X 500 Hours of Interruption)16 Tariff Equivalent Revenue $ 20,000,000
17 Ancillary Service Discount for 75 MW X 500 Hours of Economic Curtailment
18 Net Cost to Special Contract Customer
19 Special Contract Sum of 12 CP- Reflecting Actual Interruptions (MW) (Included in line
20 Special Contract Annual Energy- Reflecting Actual Interruptions (MWh) (Included in line 8)
22 System Cost Savings from Interruption
24 Allocation Factors
25 No Interruptible Service
26 SE factor (Calculated from line 4)
27 SC factor (Calculated from line 3)
28 SG factor (line 27*75% + line 26*25%)
30 With Interruptible Service (Reflecting Actual Physical Interruptions)
31 SE factor (Calculated from line 8)
32 SC factor (Calculated from line 7)
33 SG factor (line 32*75% + line 31 *25%)
38 Cost of Service
39 Energy Cost
40 Demand Related Costs
41 Sum of Cost
43 Revenues
44 Special Contract Revenue
45 Revenues from all other customers
50 Cost of Service
51 Energy Cost
52 Demand Related Costs
53 Ancillary Service Contract. Economic Curtailment (Demand)
54 Ancillary Service Contract - Economic Curtailment (Energy)
55 Sum of Cost
57 Revenues
58 Special Contract Revenue
59 Revenues from all other customers
Factor
SE1
SC1
SG1
SE2
SC2
SG2
No Interruptible Service
SE1
SG1
Situs $
Situs $
Total svstem
000
000,000
700
41 ,962,500
20,000,000
900
500,000
Jurisdiction 1
24,000
14,000,000
24,000
14,000,000
Jurisdiction 2
36,000
000,000
35,700
20,962,500
20,000,000
900
500,000
PaciliCorp
Exhibit No. 23 Page 3 of 3
Case No. PAC-E-o3-
WiUless: David L. Taylor
Jurisdiction 3
12,000
000,000
000
000,000
33.33%50.00%16.67%
33.33%50.00%16.67%
33.33%50.00%16.67%
33.36%49.96%16.68%
33.47%49.79%16.74%
33.45%49.83%16.72%
166,666,667 $
333,333,333 $
500,000,000 $
500,000,000 $
With Interruptible Service & Ancillary Service Contract
SE1
SG1
SG1
SE1
Situs $
Situs $
16,000,000
600
462,500
$4,000,000
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
500,000,000 $
000,000,000 $
1 ,500,000,000 $
000,000
480,000,000 $
498,000,000 $
998,000,000 $
000,000 $
000,000 $
500,000,000 $
20,000,000
480,000,000 $
166,000,000 $
332,666,667 $
666,667 $
666,667 $
500,000,000 $
500,000,000 $
20,000,000
000,000)
16,000,000
600
462 500
250,000,000 $
500,000,000 $
750,000,000 $
20,000,000
730,000,000 $
249,000,000 $
499,000,000 $
000,000 $
000,000 $
750,000,000 $
20,000,000
730,000,000 $
83,333,333
166,666,667
250,000,000
250,000,000
83,000,000
166,333,333
333,333
333,333
250,000,000
250,000,000
Case No. P AC-02-
Exhibit No. 24
Witness: David L. Taylor
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ACIFICORP
Exhibit AccompanYing Supplemental Direct Testimony of David L. Taylor
Appendix E - Annual Embedded Costs
July 2004
PacifiCorp
Exhibit No. 24
Case No. PAC-O2-
Witness: David L. Taylor
Protocol Appendix E
Annual Embedded Costs
Example Calculation
FERC Generation Accounts West
Line No Hydro Description Mwh $lMwh
Operating Expenses
535 - 545 Hydro Operation & Maintenance Expense 28,742,968
403.330 - 403.336 Hydro Depreciation Expense 998,326
4O4IP Hydro Relicensing Amortization
Total West Hydro Operating Expense 38,741,294
West Hydro Rate Base
330 - 336 Hydro Electric Plant in Service 374,018,924
302 Hydro Relicensing 60,297 285
108 Hydro Accumulated Depreciation Reserve (166,680,229)
154 Material & Supplies 33,115
West Hydro Net Rate Base 267 669,095
Pre-tax retum 12.040%
Rate Base Revenue Requirement 32,228,277
Annual Embedded Costs
Hydro-Electric Resources 70,969,571 128,973 17.
Mid C Contracts
555 Annual Mid-C Contracts Costs 17,395,759 942,173
Qualified Facilities
555 Annual Qualified Facilities Costs 72,455,744 904,760 80.
Generation Accounts
(Excl. West Hydro, Mid C & QF)Description
Operating Expenses
500 - 514 Steam Operation & Maintenance Expense 688,364,976
535 - 545 East Hydro Operation & Maintenance Expense 735,263
546 - 554 Other Generation Operation & Maintenance Expense 100,437,128
555 Other Purchased Power Contracts (No Mid-C or OF)967,640,792
4118 S02 Emission Allowances 567,668)
403.310 - 403.316 Steam Depreciation Expense 125,299,749
403.330 - 403.336 East Hydro Depreciation Expense 682,834
403.340 - 403.346 Other Generation Depreciation Expense 246,911
403.399 Mining
406 Amortization of Plant Acquisition Costs 5,479,353
Total Operating Expenses 900,319,339
Rate Base
310 - 316 Steam Electric Plant in Service 101,422,677
330 - 336 East Hydro EPIS 97,419,645
302 Hydro Relicensing 401,310
340 - 346 Other Electric Plant in Service 244,590,200
399 Mining 307,647,355
108 Steam Accumulated Depreciation Reserve 942,212,593)
108 Other Accumulated Depreciation Reserve (35,481,994)
108 Mining (163,138,588)
108 East Hydro Accum Depreciation Reserve (35,722,174)
114 Electric Plant Acquisition Adjustment 157,193,780
115 Accumulated Provision Acquisition Adjustment (56,601,550)
151 Fuel Stock 63,173,007
253.16-253.Joint Owner WC Deposit (4,310,538)
253.S02 Emission Allowances (45,959,734)
154 Material & Supplies
154 East Hydro Material & Supplies 46,300,904
Total Net Rate Base 739,721,705
Pre-tax retum 12.04%
(Line 42 x Line 43)Rate Base Revenue Requirement 329,871,889
( Line 25 + Line 44)Annual Embedded Costs. All Other 230,191,228 69,686,856 32.
(Line 12 + Line 13 + Line 14 + Line 45)Total Annual Embedded Costs 391,012 302 76,662,762 31.
1 . Generation Revenue Requirement less Hydro-Electric Resources, Mid Columbia Contracts and Existing OF Contracts
Case No. PAC-02-
Exhibit No. 25
Witness: David L. Taylor
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ACIFICORP
Exhibit AccompanYing Supplemental Direct Testimony of David L. Taylor
State by State Revenue Requirement Impact
% Change in Revenue Requirement
July 2004
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