2004Annual report.pdf

INSTRUCTIONS FOR FILING FERC FORMS 1, 1-F and 3-
GENERAL INFORMATION
Purpose
Form 1 is an annual regulatory support requirement under 18 CFR 141.1 for Major public utilities, licensees and others. Form 1-F is an annual regulatory
support requirement under 18 CFR 141.2 for Nonmajor public utilities, licensees and others. Form 3-0 is a quarterly regulatory support requirement which
supplements Forms 1 and 1-F under 18 CFR 141.400. The reports are designed to collect financial and operational information from major and nonmajor
electric utilities, licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be a
non-confidential public use forms.
II. Who Must Submit
Each Major electric utility, licensee, or other, as classified in the Commission s Uniform System of Accounts Prescribed for Public Utilities and Licensees
Subject To the Provisions of The Federal Power Act (18 CFR 101), must submit Form 1 as prescribed in 18 CFR Part 141.1. Each Nonmajor electric utility,
licensee or other must submit Form 1-F as prescribed in 18 CFR Part 141.2. Each Major and Nonmajor electric utility licensee or other, must submit Form
0 as prescribed in 18 CFR Part 141.400.
Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:
(1) one million megawatt hours of total annual sales,
(2) 100 megawatt hours of annual sales for resale,
(3) 500 megawatt hours of annual power exchanges delivered, or
(4) 500 megawatt hours of annual wheeling for others (deliveries plus Losses).
Nonmajor means having in each of the three 'previous calendar years, total annual sales of 10 000 megawatt hours or more
III. What and Where to Submit
(a) Submit Forms 1, 1-F and 3-0 electronically through the Form 1/3-0 Submission Software. Retain one copy of each report for your files.
(b) Respondents may submit the Corporate Officer Certification electronically, or file/mail an original signed Corporate Officer Certification to:
Chief Accountant
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
(c) Submit, immediately upon publication, four (4) copies of the latest annual report to stockholders and any annual financial or statistical report regularly
prepared and distributed to bondholders, security analysts, or industry associations. (Do not include monthly and quarterly reports. Indicate by checking the
appropriate box on Form 1 , Page 4, List of Schedules, if the reports to stockholders will be submitted or if no annual report to stockholders is prepared.) Mail
these reports to the address in lII(c) above.
(d) For the Annual CPA certification, submit with the original submission, or within 30 days after the filing date for Form 1, a letter or report (not
applicable to respondents classified as Class C or Class D prior to January 1 , 1984):
(i) Attesting to the conformity, in all material aspects, of the below listed (schedules and) pages with the Commission s applicable Uniform Systems of
Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting releases), and
(ii) be signed by independent certified public accountants or an independent licensed public accountant certified or licensed by a regulatory authority
of a State or other political subdivision of the U. S. (See 18 CFR 158.10-158.12 for specific qualifications.Reference Reference
Schedules Pages
Comparative Balance Sheet 110-113
Statement of Income 114-117
Statement of Retained Earnings 118-119
Statement of Cash Flows 120-121
Notes to Financial Statements 122-123
Insert the letter or report immediately following the cover sheet. When submitting after the filing date for this form, send the letter or report to the address
indicated at III (b). Use the following form for the letter or report unless unusual circumstances or conditions, explained in the Letter or report, demand that it
be varied. insert parenthetical phrases only when exceptions are reported.
FERC FORM NO.1 (REV. 12-99)Page i
GENERAL INFORMATION (continued)
In connection with our regular examination of the financial statements of for the year ended on which we have reported separately under date of
We have also reviewed schedules of FERC Form No.1 for the year filed with the Federal Energy Regulatory Commission, for conformity in all material
respects with the requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published
accounting releases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as we considered
necessary in the circumstances.
Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below) conform in all
material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts
and published accounting releases.
State in the letter or report, which, if any, of the pages above do not conform to the Commission s requirements. Describe the discrepancies that exist
(d) Federal, State and Local Governments and other authorized users may obtain additional blank copies to meet their requirements free of charge from:
Public Reference and Files Maintenance Branch Federal Energy Regulatory Commission 888 First Street, NE. Room 2A ED-12.2 Washington, DC 20426
(202).502-8371
IV. When to Submit:
Submit Form 1 according to the filing dates contained in section 18 CFR 141.1 of the Commission s regulations. Submit Form 1-F according to the filing
dates contained in section 18 CFR 141.2 of the Commission s regulations. Submit Form 3-0 according to the filing dates contained in section 18 CFR
141.400 of the Commission s regulations.
V. Where to Send Comments on Public Reporting Burden.
The public reporting burden for the Form 1 collection of information is estimated to average 1 144 hours per response, including the time for reviewing
instructions, searching existing data sources, gathering and maintaining the data-needed, and completing and reviewing the collection of information.public
reporting burden for the Form 1-F collection of information is estimated to average 112 hours per response. The public reporting burden for the Form 3-
collection of information is estimated to average 150 hours per response. Send comments regarding these burden estimates or any aspect of these
collections of information, including suggestions for reducing burden, to the Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC
20426 (Attention: Mr. Michael Miller, ED-30); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC
20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission). No person shall be subject to any penalty if any collection of information
does not display a.valid control number (44 U.C. 3512 (an.
FERC FORM NO.1 (REV. 12-99)Page ii
GENERAL INSTRUCTIONS
I. Prepare this report in conformity with the Uniform System of Accounts (18 CFR 101) (U.S. of A). Interpret all accounting words and phrases in
accordance with the U. S. of A
II. Enter in whole numbers (dollars or MWH) only, except where otherwise noted. (Enter cents for averages and figures per unit where cents are important.
The truncating of cents is allowed except on the four basic financial statements where rounding is required.) The amounts shown on all supporting pages
must agree with the amounts entered on the statements that they support. When applying thresholds to determine significance for reporting purposes, use for
balance sheet accounts the balances at the end of the current reporting period, and use for statement of income accounts the current year's year to date
amounts.
III Complete each question fully and accurately, even if it has been answered in a previous report. Enter the word "None" where it truly and completely
states the fact.
IV. For any page(s) that is not applicable to the respondent, omit the page(s) and enter "NA,
" "
NONE " or "Not Applicable" in column (d) on the List of
Schedules, pages 2 and 3.
V. Enter the month, day, and year for all dates. Use customary abbreviations. The "Date of Report" included in the header of each page is to be completed
only for resubmissions (see VII. below).
VI. Generally, except for certain schedules, all numbers, whether they are expected to be debits or credits, must be reported as positive. Numbers having a
sign that is different from the expected sign must be reported by enclosing the numbers in parentheses.
VII For any resubmissions, submit the electronic filing using the Form 1/3-0 software and send a letter identifying which pages in the form have been
revised. Send the letter to the Office of the Secretary.
VIII.Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.
IX. Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the report of the
previous period/year, or an appropriate explanation given as to why the different figures were used.
Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:
FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended to remain reliable
even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.
Self" means the respondent.
FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under
adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.
LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and "firm" means that service cannot be
interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point Transmission ReservationsB are described
in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in a footnote the termination date of the contract
defined as the earliest date either buyer or seller can unilaterally cancel the contract.
OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open Access
Transmission Tariff. "Long-Term" means one year or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to
remain reliable even under adverse conditions. For all transactions identified as OLF, provide in a footnote the termination date of the contract defined as the
earliest date either buyer or seller can unilaterally get out of the contract.
SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations, where the
duration of each period of reservation is less than one-year.
NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain reliable even
under adverse conditions.
OS - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentioned classifications, such as all
other service regardless of the length of the contract and service form. Describe the type of service in a footnote for each entry.
AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an
explanation in a footnote for each adjustment.
DEFINITIONS
I. Commision Authorization (Comm. Auth.) -- The authorization of the Federal Energy Regulatory Commission, or any other Commission. Name the
commission whose authorization was obtained and give date of the authorization
II. Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report is made.
FERC FORM NO.1 (REV. 12-99)Page ill
EXCERPTS FROM THE LAW
Federal Power Act, 16 U.C. 791 a-825r
Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to wit: ... (3) . corporation' means any corporation
joint-stock company, partnership, association, business trust, organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or
trustees of any of the foregoing. It shalt not include 'municipalities, as hereinafter defined;
(4) 'Person' means an individual or a corporation;
(5) 'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successor in interest
thereof;
(7) 'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the Laws
thereof to carry an the business of developing, transmitting, unitizing, or distributing power; ......
(11) "project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams and appurtenant works
and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or forebay reservoirs directly connected therewith, the
primary line or Lines transmitting power therefrom to the point of junction with the distribution system or with the interconnected primary transmission system
all miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs
Lands, or interest in Lands the use and occupancy of which are necessary or appropriate in the maintenance and operation of such unit;
Sec. 4. The Commission is hereby authorized and empowered
(a) To make investigations and to collect and record data concerning ;he utilization of the water 'resources of any region to be developed, the
water-power industry and its relation to other industries and to interstate or foreign commerce, and conceming the location, capacity, development -costs, and
relation to markets of power sites; ... to the ext~nt the Commission may deem necessary or useful for the purposes of this Act"
Sec. 304. (a) Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as the Commission
may be rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the -proper administration of this Act The
Commission my prescribe the manner and form in which such reports shalt be made, and require from such persons specific answers to all questions upon
which the Commission may need information. The Commission may require that such reports shall include, among other things, full information as to assets
and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project
and other facilities, cost of maintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other
facilities, depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such person-to
make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unless the Commission otherwise
specifies
Sec. 309. The Commission shall have power to perform any and all acts, and to prescribe, issue, make, and rescind such orders, rules and regulations as it
may find necessary or appropriate to carry out the provisions of this Act Among other things, such rules and regulations may define accounting, technical
and trade terms used in this Act; and may prescribe the *form or forms of all statements, declarations, applications, and reports to be filed with the
Commission, the information which they shall contain, and the time within which they shall be field...
i GENERAL PENALTIESI "Sec. 315. (a) Any licensee or public utility which willfully fails, within the time prescribed by the Commission, to comply with any order of the Commission, to
file any report required under this Act or any rule or regulation of the Commission thereunder, to submit any information of document required by the
Commission in the course of an investigation conducted under this Act .... shall forfeit to the United States an amount not exceeding 000 to be fixed by the
Commission after notice and opportunity for hearing .... "
FERC FORM NO.1 (ED. 12-91)Page Iv
FERC FORM NO. 1/3-
REPORT OF MAJOR ELECTRIC UTiliTIES. liCENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent
PacifiCorp
03 Previous Name and Date of Change (if name changed during year)
02 Year/Period of Report
End of 2004/Q4
1 1
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
825 N.E. Multnomah, Suite 2000 Portland, OR 97232
05 Name of Contact Person
Henry Lay
07 Address of Contact Person (Street, City, State, Zip Code)
825 N.E. Multnomah, Suite 1900 Portland, OR 97232
06 Title of Contact Person
Corp Accounting Controller
08 Telephone of Contact Person lncluding 09 This Report Is
Area Code (1) 00 An Original
[phone]
(2) D A Resubmission
10 Date of Report
(Mo, Da, Yr)
04/25/2005
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned officer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Uniform System of Accounts.
01 Name 03 Signature lIt 04 Date SignedRichard D. Peach
! '
(Mo, Da, Yr)
02 Title 't-\r;;..\J\.~f.j
",\,
Chief Financial Officer Richard D. Peach 04/25/2005
Title 18, U.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
FERC FORM No.1/3-Q (REV. 02-04)Page
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) DA Resubmission 04/25/2005
LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms "none
" "
not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none
" "
not applicable " or "NA"
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
General Information 101
Control Over Respondent 102
Corporations Controlled by Respondent 103
Officers 104
Directors 105
Important Changes During the Year 108-109
Comparative Balance Sheet 110-113
Statement of Income for the Year 114-117
Statement of Retained Earnings for the Year 118-119
Statement of Cash Flows 120-121
Notes to Financial Statements 122-123
Statement of Accum Comp Income, Comp Income, and Hedging Activities 122(a)(b)
Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
Nuclear Fuel Materials 202-203
Electric Plant in Service 204-207
Electric Plant Leased to Others 213
Electric Plant Held for Future Use 214
Construction Work in Progress-Electric 216
Accumulated Provision for Depreciation of Electric Utility Plant 219
Investment of Subsidiary Companies 224-225
Materials and Supplies 227
Allowances 228-229
Extraordinary Property Losses 230
Unrecovered Plant and Regulatory Study Costs 230
Other Regulatory Assets 232
Miscellaneous Deferred Debits 233
Accumulated Deferred Income Taxes 234
Capital Stock 250-251
Other Paid-in Capital 253
Capital Stock Expense 254
Long-Term Debit 256-257
Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 261
Taxes Accrued, Prepaid and Charged During the Year 262-263
Accumulated Deferred Investment Tax Credits 266-267
Other Deferred Credits 269
Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273
FERC FORM NO.1 (ED. 12-96)Page 2
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) Fi A Resubmission 04/25/2005
LI :jT OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none,
" "
not applicable,. or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none
" "
not applicable," or "NA"
Line Title of Schedule Reference Remarks
No.Page No.
(a)(b)(c)
Accumulated Deferred Income Taxes-Other Property 274-275
Accumulated Deferred Income Taxes-Other 276-277
Other Regulatory Liabilities 278
Electric Operating Revenues 300-301
Sales of Electricity by Rate Schedules 304
Sales for Resale 310-311
Electric Operation and Maintenance Expenses 320-323
Purchased Power 326-327
Transmission of Electricity for Others 328-330
Transmission of Electricity by Others 332
Miscellaneous General Expenses-Electric 335
Depreciation and Amortization of Electric Plant 336-337
Regulatory Commission Expenses 350-351
Research, Development and Demonstration Activities 352-353
Distribution of Salaries and Wages 354-355
Common Utility Plant and Expenses 356
Purchases and Sales of Ancillary Services 398
Monthly Transmission System Peak Load 400
Electric Energy Account 401
Monthly Peaks and Output 401
Steam Electric Generating Plant Statistics (Large Plants)402-403
Hydroelectric Generating Plant Statistics (Large Plants)406-407
Pumped Storage Generating Plant Statistics (Large Plants)408-409
Generating Plant Statistics (Small Plants)410-411
Transmission Line Statistics 422-423
Transmission Lines Added During Year 424-425
Substations 426-427
Footnote Data 450
Stockholders' Reports Check appropriate box:
(!)
Four copies will be submitted
No annual report to stockholders is prepared
FERC FORM NO.1 (ED. 12-96)Page 3
Name of Respondent
PacifiCorp
This Report Is:
(1) 00 An Original(2) D A Resubmlssion
Date of Report
(Mo, Oa, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
GENERAL INFORMATION
1. Provide name and title of officer having custody of the general corporate books of account and address of
office where the general corporate books are kept, and address of office where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
Richard D. Peach, Chief Financial Officer
825 N.E. Multnamah, Suite 2000
Portland, OR 97232-4116
Corporate ~ks are kept at:
825 N.E. Multnamah, Suite 2000
Portland, OR 97232-4116
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
of organization and the date organized.
Incorporated on August 11, 1987 in the State of Oregon.
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
Not applicable.
Not applicable.
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
The Company is a regulated electric company operating in portions of the states of Utah, Oregon,
wyamdng, Washington, Idaho and California. The Company conducts its retail electric utility business as
Pacific Power and Utah Power, and engages in electricity production and sales on a wholesale basis under
the name pacifiCorp.
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year s certified financial statements?
(1) D Yes...Enter the date when such independent accountant was initially engaged:(2) 00
FERC FORM No.1 (ED. 12-87)PAGE 101
Name of Respondent
PacifiCorp
This Report Is:
(1) IX) An Original(2) D A Resubmission
CONTROL OVER RESPONDENT
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held
control over the repondent at the end of the year, state name of controlling corporation or organization, manner in
which control was held, and extent of control. If control was in a holding company organization, show the chain
of ownership or control to the main parent company or organization. If control was held by a trustee(s), state
name of trustee(s), name of beneficiary or beneficiearies for whom trust was maintained, and purpose of the trust.
Scottish Power pic
Scottish Power NA 1 Limited (10% controlled) Equity Investment
Scottish Power NA 2 Limited (90% controlled) Equity Investment
PacifiCorp Holdings, Inc. (100% controlled) Equity Investment
PacifiCorp (100% controlled) Equity Investment
FERC FORM NO.1 (ED. 12-96)Page 102
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
CORPORATIONS CONTROLLED BY R SPONDENT
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by
mutual agreement or understanding between two or more parties who together have control within the meaning of the definition of
control in the Uniform System of Accounts, regardless of the relative voting rights of each party.
Line Name of Company Controlled Kind of Business Percent Voting Footnote
No.Stock Owned Ref.(a)(b)(c)(d)
Centralia Mining Qompany Mining 100
Energy West Mining Company Mining 100
Glenrock Coal Company Mining 100
Interwest Mining Company Mining 100
Pacific Minerals, Inc Mining 100
Bridger Goal Company Mining 66.
Pac ifiGorp. Environ m entaJRemedia tionCo Environmental Services 89.
PacifJCorp FutureGenerations,lnc Rain Forest Carbon Credits 100
PacifiCorp Investment Management, Inc Management Services for PERCO 100
FERC FORM NO.1 (ED. 12-96)Page 103
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
OFFICERS
Report below the name, title and salary for each executive officer whose salary is $50,000 or more.An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change in incumbency was made.
Line Title Name of Officer Salary
No.for Year
(a)(b)(c)
President and Chief Executive Officer Judith A. Johansen
~~.
Senior Vice President, General Counsel and Corporate Andrew P. Haller
Secretary
Senior Vice President Michael J. Pittman
Executive Vice President A;Filc.h8fd~.
Executive Vice President Matthew R. Wright _~~lS:
Senior Vice President Robert A. Klein
Executive Vice President iII~
Executive Vice President Andrew N. MacRitchie
Senior Vice President Barry G. Cunningham
Senior Vice President Donald N. Furman
Senior Vice President
Senior Vice President Stan K. Watters
Vice President
Vice President Donald D. Larson
Vice President Ernest E. Wessman
Chief Financial Officer Richard D. Peach
Vice President & Treasurer Bruce N. Williams
FERC FORM NO.1 (ED. 12-96)Page 104
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
DIRECTORS
1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviated
titles of the directors who are officers of the respondent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
Llllt::Name (anp Title) of Director PrinCIpal Business AOOressNo.(a)(b)
PacifiCorp Board of Directors:
Ian M. Russell, Chair 1 Atlantic Ouay
Glasgow, Scotland G2 8SP
Judith A. Johansen (President & CEO)825 NE Multnomah, Suite 2000
Portland, Oregon 97232
~1 ~~ ~n, Su~ ~OO10 Salt Lake City, Utah 84140
"""
Andrew N. MacRitchie (Executive Vice President)825 NE Multnomah, Suite 2000
Portland, Oregon 97232
"""
Matthew R. Wright (Executive Vice President)825 NE Multnomah, Suite 2000
Portland, Oregon 97232
"""
Barry G. Cunningham (Senior Vice President)201 South Main, Suite 2300
Salt Lake City, Utah 84140
"""
Michael J. Pittman (Senior Vice President)825 NE Multnomah, Suite 2000
Portland, Oregon 97232
~1 So~h Main, Su~ ~OO
Salt Lake City, Utah 84140
Nolan E. Karras 4695 South 1900 West #3
Roy, Utah 84067
""" Andrew P. Haller (Senior Vice President)825 NE Multnomah, Suite 2000
Portland, Oregon 97232
"""
Richard D. Peach (Chief Financial Officer)825 NE Multnomah, Suite 2000
Portland, Oregon 97232
FERC FORM NO.1 (ED. 12-95)Page 105
Name of Respondent
PacifiCorp
YearlPeriod of Report
End of 2004/04This Report Is: Date of Report
(1) I!I An Original(2) D A Resubmission 04/25/2005
1M ORTANT CHANGES DURING THE QUARTERNEAR
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none,
" "
not applicable," or "NA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquire~ without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto,
and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given , assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,
director, security holder reported on Page 106, voting trustee, associated company or known associate of any of these persons was a
party or in which any such person had a material interest.
11. (Reserved.
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have
occurred during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 108
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
ITEM 1.
State
California
None
Idaho
Mud Lake
Hamer
Franklin
Rexburg
Ore
Culver
Hood River (a)
Rufus
Utah
Rich County
Redmond
Wellington
Lewiston
Price
Smithfield
San Juan County
Richmond
Washin
Asotin County (b)
College Place
omin
None
Effective Date iration Date Fee %
(Fee attached to franchise agreement)
07/02/2004*
09/09/2004*
09/28/2004
12/09/2004
06/09/2028
08/26/2034
1 % 1/2034
12/09/2039
0% franchise
0% franchise
0% franchise
03/08/2004*
06/02/2004
11/09/2004
03/08/2024
06/02/2009
11/09/2024
5% franchise
5% franchise
04/08/2004 *
02/25/2004 *
06/17/2004 *
08/10/2004*
09/28/2004
10/22/2004
10/27/2004
12/01/2004
02/03/2029
02/11/2029
06/1 7/2024
04/05/2024
09/28/2024
10/22/2024
10/27/2024
12/01/2024
03/02/2004 *
09/03/2004 *
03/02/2014
09/03/2024 6% franchise
* Denotes a change from the originally reported effective date, which was the date the governing body actually approved the franchise
rights, not the date it was accepted by the Company and made officially effective.
(a) 5% (3.5% franchise; 1.5% license)
(b) Renewable for additional ten years upon mutual consent
ITEM 2.
None
ITEM 3.
PacifiCorp has sold the Naches and Naches Drop Hydroelectric Plants to the United States Bureau of Reclamation. Water Rights,
along with some buildings and equipment were turned over to the Bureau of Reclamation on March 10,2003. Access to the remainder
of the building and equipment was granted to the United States Bureau of Reclamation effective January 1 2004. The third
amendment to the water rights purchase agreement was executed November 1,2004. Transfer of the land rights per this agreement
occurred on March 31 , 2005. A letter dated July 28, 2004 to the Federal Energy Regulatory Commission (the "FERC") for permission
FERC FORM NO.ED. 12-96 Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
to clear FERC account Electric Plant Purchased or Sold ("account 102"), was approved by FERC on November 22, 2004.
PacifiCorp and six other minority owners sold their interest in the 1 MW Skookumchuck Hydroelectric project to a subsidiary of
Alberta Canada based TransAlta for $7.4 million. PacifiCorp s share was $3.5 million. The sale was completed on October 5th, 2004,
with the proceeds, net book value, and selling costs transferred to FERC account 102. Additional closing costs were booked in
December 2004 and cleared to FERC account 102. A letter to the FERC for permission to clear account 102 is pending.
ITEM 4.
In May 2002, PacifiCorp entered into a 15-year operating lease for an electric generation facility with West Valley Leasing Company,
LLC ("West Valley ). West Valley is a subsidiary ofPPM Energy, Inc. ("PPM"), which is a direct subsidiary of Pacific Holdings, Inc.
PID") and an indirect subsidiary of ScottishPower. The facility consists of five generation units, each rated at 40 megawatts ("MW"
and is located in Utah. The lease terms granted PacifiCorp two independent early termination options that provide PacifiCorp the right
to terminate the lease and, at PacifiCorp s further option, to purchase the facility for predetermined amounts. On May 28,2004
PacifiCorp exercised its first option to terminate the West Valley lease. PacifiCorp subsequently exercised its right to rescind the
termination on September 28, 2004 after determining, through a public process, that the resource could not be replaced on a more
economic basis and without increasing reliability risk to the system. PacifiCorp has a second option to terminate the West Valley lease
if written notice is provided to West Valley on or before December 1, 2006. PacifiCorp is committed to future minimum lease
payments of $15.0 million annually for years ending March 31, 2005 through 2008 and $2.5 million for the year ending March 31,
2009.
In December 2003 , PacifiCorp entered into a Precedent Agreement For Firm Transportation Service on Questar Pipeline Company
QPC") Currant Creek Lateral (Precedent Agreement) which outlined the terms of a requested Transportation Service Agreement
(TSA) and construction of a natural gas pipeline and facilities necessary to connect the Currant Creek Power Project to QPC's Kern
River Goshen interconnect receipt point. Upon completion of the pipeline construction, PacifiCorp and QPC entered into a 30-year
TSA, with a lease term beginning April 1, 2005. The TSA utilizes an Initial Monthly Reservation (IMR) charge of
$0.80977/decatherm based on usage of a minimum 190,000 decatherms per month. The reservation charges decrease to 90% of the
IMR for years six through ten, 80% of the IMR for years eleven through fifteen and 70% of the IMR for years sixteen through thirty.
The TSA is considered a capital lease of the facilities and PacifiCorp is committed to future minimum lease payments, including
executory costs, of approximately $1.8 million per year for PacifiCorp s fiscal years ending March 31, 2006 through 2010; $1.7
million per year for fiscal years ending March 31, 2011 - 2015; $1.5 million per year for fiscal years ending March 31, 2016 - 2020;
and, $1.3 million per year for fiscal years ending March 31 , 2021 - 2035.
ITEM 5.
Please refer to page 424-425 Transmission Lines Added During the Year of this Form No.
ITEM 6.
Short-Term Debt
At April 21, 2005, PacifiCorp had $ 545.0 million of commercial paper obligations outstanding, with maturities of less than one year.
Authorizations for up to $1.5 billion outstanding at anyone time in commercial paper and other unsecured short-term debt are as
follows:
Oregon Public Utility Commission, Docket No. UF-4120, Order No. 98-158, dated April 16, 1998.
Washington Utilities and Transportation Commission, Docket No. UE-980404, dated April 8, 1998.
Idaho Public Utility Commission, Case No. PAC-03-, Order No. 29374, dated November 5,2003.
At December 31, 2004, PacifiCorp had an $800.0 million committed bank revolving credit agreement, which was fully available, and
FERC FORM NO. ED. 12-96 Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
which had no borrowings outstanding. This facility, which has a three-year term, became effective May 28, 2004 and was used to
replace an expiring $500.0 million facility, as well as a $300.0 million facility that was terminated by PacifiCorp prior to its maturity.
The interest on advances under' this new facility is based on the London Interbank Offered Rate (LffiOR) plus a margin that varies
based on PacifiCorp s credit rating.
Long- Term Debt
On August 24 2004, PacifiCorp issued $200.0 million of its 4.95% Series of First Mortgage Bonds due August 15,2014, and $200.
million of its 5.90% Series of First Mortgage Bonds due August 15,2034. PacifiCorp used the proceeds for general corporate
purposes, including the reduction of short-term debt. Authorizations for the issuances were as follows:
Oregon Public Utility Commission, Docket No. UF-4167, Order No. 99-786, dated December 23, 1999 and Supplemental Order No.
01-965, dated November 13,2001.
Washington Utilities and Transportation Commission, Docket No. UE-991745, dated December 8, 1999.
Idaho Public Utilities Commission, Case No. P AC-03-06, Order No. 29238, dated May 14,2003.
During December 2004, PacifiCorp redeemed, prior to maturity, all of the 8.625% First Mortgage Bonds due in December 2024,
which totaled $20.0 million. This retirement was initially funded through short-term debt with the expectation that it will be funded
through long-term financing in the next 12 months, subject to regulatory authorization.
During March 2005, the maturity date was extended for $38.1 million of pollution control revenue bond obligations as follows:
(Millions of dollars)
Issue Issuer Amount Original Maturity New Maturity
Converse Co, WY 22.7/1 /2006 12/112020
Sweetwater Co, WY 4/112005 12/112020
Sweetwater Co, WY 12/1 /2005 12/1/2020
38.
Pollution Control Revenue Refunding Bonds, Series 1992
Pollution Control Revenue Refunding Bonds, Series 1992A
Pollution Control Reven ue Refunding Bonds, Series 1992B
Total pollution control revenue bonds
In April 2005, PacifiCorp filed applications requesting authority to issue up to $1.0 billion of long-term debt with the Oregon Public
Utility Commission, Washington Utilities and Transportation Commission and Idaho Public Utilities Commission.
Common Stock
In April 2005, PacifiCorp filed applications requesting to increase the existing authority to issue new common stock to its immediate
corporate parent by 14 851,485 shares to bring the authorized total up to 50 000,000 new shares with the Oregon Public Utility
Commission, Washington Utilities and Transportation Commission and the Idaho Public Utilities Commission.
Other Financing Arrangements
In September 2004, PacifiCorp entered into a new $296.9 million letter of credit facility with a maturity date of September 14 2007.
This facility provides credit enhancement and liquidity support for seven series of variable rate pollution control revenue bond
obligations. In connection with the commencement of this new facility, corresponding amounts of previously existing letters of credit
were cancelled.
At December 31, 2004, PacifiCorp had $517.8 million of standby letters of credit and standby bond purchase agreements, including
the new letter of credit facility, available to provide credit enhancement and liquidity support for variable-rate pollution control
revenue bond obligations. These committed bank arrangements expire periodically through the year ending December 31, 2007.
Subsequent to December 31, 2004, approximately $96.5 million of these committed bank arrangements were extended through January
FERC FORM NO.ED. 12-Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmisslon 04/25/2005 2004/04
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
2010.
PacifiCorp s credit agreements contain customary covenants and default provisions, including covenants not to exceed a specified
debt-to-capitalization ratio. PacifiCorp monitors these covenants on a regular basis to ensure that events of default will not occur. As of
December 31, 2004, PacifiCorp was in compliance with the covenants of its credit agreements.
ITEM 7.
None
ITEM 8.
The following table represents the estimated financial impact of the wage scale increase on the twelve months ended December
312004:
Unions Effective Estimated
Re p resen t ed % Increase (a)Date(s)Financial Impact
IBEW 57 Generation 76%1/26/2004 & 7/26/2004 080 450
IBEW 57 Power Delivery 03%1/26/2004 & 7/26/2004 693,679
IBEW 127 (WY)00%3/26/2004 & 9/26/2004 196 119
UWUA 197 (Coos Bay, OR)85%1/26/2004 & 7/26/2004 86,394
IBEW 57 West Valley 00%5/26/2004 986
IBEW 415 (Laramie, WY)06%6/26/2004 & 9/26/2004 13,355
IBEW 125 (W A & OR)59%1/2612004 & 7/26/2004 927,704
IBEW 659 (OR & CA)88%1/26/2004 & 7/26/2004 097,430
Total 104 117
(a) This percentage increase represents the increase of wages for all effective dates during the calendar year
related to the wage scale of the prior effective period.
ITEM 9.
INFORMA TION REGARDING RECENT REGULA TORY DEVELOPMENTS
FERC Matters
For a discussion on FERC issues, see Notes to the Financial Statements - Note 7 - Commitments and Contingencies of this Form No.
Hydroelectric Actions
Several of PacifiCorp' s hydroelectric plants are in some stage of the relicensing or decommissioning process with the FERC The
following summarizes the status of these projects.
Relicensin
FERC FORM NO.ED. 12-Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 04/25/2005 2004/04
IMPORTANT CHANGES DURING THE OUARTER/YEAR (Continued)
Bear River h droelectric ect - (Bear River, IdaholUtah)
In December 2003, the FERC issued a new 30-year operating license for the 84.5 MW Bear River hydroelectric project. The license
became final and PacifiCorp accepted the new license on May 25,2004. The FERC included in the Bear River s license a requirement
to evaluate decommissioning the 7.5 MW Cove plant and associated project features. As part of this evaluation, PacifiCorp has been
working with stakeholders to determine the actions that would be required to decommission this plant. In addition to the project's
capital and operations and maintenance costs associated with the new license, PacifiCorp is committed, over the life of the license, to
fund approximately $26.5 million for environmental mitigation and enhancement projects. A $12.2 million liability, representing the
present value of these obligations, was recorded in May 2004.
Klamath h droelectric ect - (Klamath River, Oregon and California)
In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 161.4 MW Klamath hydroelectric
project. The FERC is scheduled to complete its required analysis by April 2006. In the meantime, PacifiCorp continues to work
cooperatively with a broad range of stakeholders to identify and resolve any outstanding issues in an attempt to reach a settlement. In
October 2004, PacifiCorp convened a mediated settlement negotiation group consisting of itself, state and federal agencies, Native
American tribes, and other stakeholders, in an effort to reach a comprehensive agreement on project relicensing.
Lewis River h droelectric ects - (Lewis River, Washington)
PacifiCorp filed new license applications for the 136.0 MW Merwin and 240.0 MW Swift No.1 hydroelectric projects in April 2004.
An application for a new license for the 134.0 MW Yale hydroelectric project was filed with the FERC in April 1999. However,
consideration of the Yale application was delayed pending filing of the Merwin and Swift No.1 applications so that the FERC could
complete a comprehensive environmental analysis.
On November 30, 2004, PacifiCorp executed a comprehensive settlement agreement with 25 other parties including state and federal
agencies, Native American tribes, conservation groups, and local government and citizen groups to resolve, among the parties, issues
related to the pending applications for new licenses for PacifiCorp s 136.0 MW Merwin, 240.0 MW Swift No.1 and 134.0 MW Yale
hydroelectric projects. As part of this settlement agreement, PacifiCorp has agreed to implement certain protection, mitigation and
enhancement measures prior to and during a proposed 50-year license period. However, these commitments are contingent on
ultimately receiving a license from the FERC that is consistent with the settlement agreement, and other required permits. The FERC is
scheduled to complete its process and required analysis in order to be ready for a decision in March 2006.
North Um ua h droelectric ect - (North Umpqua River, Oregon)
In November 2003, the FERC issued a new 35-year operating license for the 188.5 MW North Umpqua hydroelectric project. Both
PacifiCorp and environmental groups sought rehearing of the license, and in March 2004, the FERC issued an order on rehearing
favorable to PacifiCorp and denying the motion of the environmental groups. In May 2004, the environmental groups appealed the
FERC order in the Ninth Circuit Court of Appeals, where the case is currently pending. The new FERC license is currently effective
but not final, and certain implementation measures may be delayed pending the outcome of the appeal. In addition to the project's
capital and operations and maintenance costs associated with the new license, when the license becomes final PacifiCorp will be
committed, over the life of the license, to fund approximately $48.9 million for environmental mitigation and enhancement projects. A
$13.0 million liability, representing the present value of certain obligations specified in the license, was recorded in June 2004.
Additional liabilities will be recognized when the license becomes final.
Pros ect h droelectric ect - (Rogue River, Oregon)
In June 2003, PacifiCorp submitted a final license application to the FERC for the Prospect Nos. 1,2 and 4 hydroelectric projects,
which total 36.8 MW. The FERC is expected to complete its required analysis and issue a new license by the end of fiscal year 2006.
Decommissionin
American Fork h droelectric ect - (American Fork River, Utah)
The FERC issued a surrender order for American Fork on August 4, 2004, which calls for project removal to be completed by
December 2007. Removal costs for this 1.0 MW project are estimated to be approximately $1.1 million, including process and
permitting costs. The parties have agreed that project removal will begin in September 2006, subject to FERC and other regulatory
approvals, with operations continuing until that time.
FERC FORM NO.ED. 12-96 Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
Condit h droelectric ect - (White Salmon River, Washington)
In September 1999, a settlement agreement to remove the 9.6 MW Condit hydroelectric project was signed by PacifiCorp, state and
federal agencies, and non-governmental agencies. Under the original settlement agreement, removal was expected to begin in October
2006, for a total cost to decommission not to exceed $17.2 million, excluding inflation. In early February 2005, the parties agreed to
modify the settlement agreement so that removal will not begin until October 2008 for a total cost to decommission not to exceed
$20.5 million, excluding inflation. The settlement agreement is contingent upon receiving an amended FERC license and removal
order, which is not materially inconsistent with the amended settlement agreement and other regulatory approvals. PacifiCorp is in the
process of acquiring all necessary permits, within the terms and conditions of the amended settlement agreement.
Powerdale h droelectric ect - (Hood River, Oregon)
In June 2003, PacifiCorp entered into a settlement agreement to remove the 6.0 MW Powerdale plant rather than pursue a new license,
based on an analysis of the costs and benefits of relicensing versus decommissioning. Removal of the Powerdale plant and associated
project features, which is subject to the FERC and other regulatory approvals, is projected to ultimately cost $6.3 million. The plant
will continue to operate until its removal, which will commence in 2010.
State Regulatory Issues
PacifiCorp pursues a regulatory program in all states that it serves, with the objective of keeping rates closely aligned to ongoing costs.
The following is a state-by-state update:
Utah
On August 4,2004, PacifiCorp filed a general rate case request with the Utah Public Service Commission (the "UPSC") for
approximately $111.0 million annually related to operating cost increases and recovery of investments that support Utah's growing
demand and need for enhanced network reliability. In October 2004, the UPSC approved the use of a forward-looking test year in this
general rate case, the fiscal year 2006. PacifiCorp filed rebuttal testimony in January 2005 reducing the revenue requirement request
from $111.0 million to $96.3 million. The main reasons for the change were to reflect increased revenues from updated customer
contracts and to update specific items in the filing. In February 2005, the UPSC approved a stipulation settling the general rate case.
Under the stipulation, PacifiCorp was awarded an increase in prices of $51.0 million annually, resulting in an average price increase of
66%, and an allowed return on equity of 10.5%. The stipulation also included an effective date of March 1,2005, which was a
month earlier than the April 1, 2005 date required by Utah statute, resulting in a one-time benefit of $4.3 million of additional
revenues. As a result, base rates in Utah increased by $51.0 million starting in March 2005.
Senate Bill 26 ("SB 26") was signed into law in February 2005. This bill establishes rules and a mandatory process for the solicitation
and evaluation of bids to procure significant energy resources. It also provides PacifiCorp with the opportunity to obtain advance
approval from the UPSC of a resource decision and an assurance of the recovery of costs associated with the resource. SB 26 also
establishes a voluntary process for utilities to obtain advance approval of certain other resource commitments and investment
decisions.
In January 2004, the UPSC approved a stipulation settling PacifiCorp s general rate case filed in May 2003. Under the stipulation, base
rates in Utah increased by $65.0 million annually starting in April 2004, resulting in an average price increase of7.0% and an
authorized return on equity of 10.7%.
Oregon
In November 2000, PacifiCorp made a defeITed accounting filing to track its excess net power costs. In July 2002, the Oregon Public
Utility Commission (the "OPUC") approved the filing, finding that PacifiCorp had prudently incurred the excess net power costs. The
order authorized recovery of $131.0 million, plus carrying charges, a rate of $45.6 million annually. The Industrial Customers of
Northwest Utilities and the Citizens' Utility Board appealed the OPUC order. The Marion County, Oregon circuit court affirmed the
OPUC order. The Industrial Customers of Northwest Utilities and the Citizens' Utility Board appealed the circuit court decision to the
Oregon Court of Appeals. The Court of Appeals heard oral arguments in May 2004. On October 27, 2004, the Oregon Court of
FERC FORM NO.ED. 12-Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
IMPORTANT CHANGES DURING THE OUARTER/YEAR (Continued)
Appeals affirmed the circuit court decision. The deadline for further appeals has passed. As of March 31 2005, approximately $13.
million remained to be collected by the authorized surcharge.
On November 12,2004, PacifiCorp filed a general rate case with the OPUC related to increases in operating costs, including
fuel, purchased power, and pension and health care costs. PacifiCorp is seeking an increase of $102.0 million annually, or
12.5%. If approved by the OPUC, the increase would take effect in September 2005. Settlement conferences were held in
April 2005 and hearings are scheduled to occur in July 2005.
PacifiCorp filed an application in February 2005 for deferral of higher power costs in calendar 2005 due to continuing poor
hydroelectric conditions. PacifiCorp seeks deferral of these costs to track and preserve them for later incorporation in rates. PacifiCorp
also filed a power cost adjustment mechanism in April 2005 to address volatility in PacifiCorp s total net power costs, including
hydroelectric variability. PacifiCorp has filed a motion to consolidate the hydroelectric deferral and the power cost adjustment
mechanism filings. It is anticipated that deferral of hydroelectric impacts will be incorporated into the power cost adjustment
mechanism as a longer-term mechanism to address total net power cost variability.
Wyoming
In March 2003, the Wyoming Public Service Commission (the "WPSC") denied recovery of the Hunter No.1 replacement power costs
and the deferred excess net power costs. On appeal, the Laramie County District Court certified the case to the Wyoming Supreme
Court. PacifiCorp filed its reply brief in April 2004. Oral arguments before the Wyoming Supreme Court took place in June 2004. On
December 13, 2004, the Wyoming Supreme Court issued its decision affirming the Order of the Public Service Commission to deny
recovery of replacement power and deferred excess net power costs.
Also, in April 2004, PacifiCorp filed a complaint with the federal district court in Wyoming challenging the WPSC's March 2003
decision on the grounds that the decision violates federal law by denying PacifiCorp recovery in retail rates of its wholesale electricity
and transmission costs incurred to serve Wyoming customers. The lawsuit seeks an injunction requiring the WPSC to pass through
PacifiCorp s wholesale electricity and transmission costs in retail rates. In May 2004, the WPSC filed a motion to dismiss the
complaint. Oral arguments on the motion to dismiss took place in September 2004. The motion to dismiss was denied on November 5,
2004. On January 11,2005, the defendants appealed the court's ruling on the motions to dismiss and requested a stay of the underlying
litigation. On January 31, 2005 PacifiCorp filed its brief in opposition to defendants' interlocutory appeal of the court s ruling. In
February 2005, the Tenth Circuit Court denied the defendants' interlocutory appeal of the court s ruling. The Defendants' appeal on
sovereign immunity grounds is pending at the Tenth Circuit Court. The Defendants' opening brief was filed on April 4, 2005 and
PacifiCorp s response brief is due on May 9,2005.
In July 2004, PacifiCorp applied to the WPSC for a stand-alone pass-on of increased net wholesale purchased electricity costs.
Following discussions with various parties, PacifiCorp filed a joint stipulation reducing this request to $9.25 million, or 2.68%. This
stipulation was heard by the WPSC on September 14 2004 and approved effective September 15,2004. The expedited treatment of
this application was recognized in the stipulation with an agreement that PacifiCorp will not file a general rate application until at least
September 30, 2005. Further, the parties agreed to hold discussions on the development of a commodity cost recovery mechanism
and alternative forms of regulation ("AFaR"). Meetings have taken place with the parties to evaluate inputs into a commodity cost
recovery mechanism and an AFaR. PacifiCorp continues to study the stated interests of the parties in these regulatory mechanisms and
how they might affect the risk of doing business in Wyoming.
In June 2004, the WPSC concluded hearings on the joint application of Powder River Energy Corporation and Kennecott Energy
Company for a certificate of public convenience and necessity to serve the Antelope Coal Mine in Converse County, Wyoming. The
Antelope Coal Mine is in PacifiCorp s service territory and PacifiCorp has been serving this mine for 20 years. The joint application
proposed a dual certificate arrangement that would allow Kennecott Energy Company to choose its electric service provider.
PacifiCorp argued that it should be the sole service provider. The WPSC deliberated this issue in September 2004 and directed parties
to enter into further discussions over a six- to eight-week period to determine whether a solution can be proposed that keeps the
authorized service telTitory of PacifiCorp and Powder River Energy Corporation intact. On October 28, 2004, the WPSC approved a
stipulation that was filed by PacifiCorp, Powder River Energy Corporation and Kennecott Energy Company. The terms of the
stipulation include a continued recognition of PacifiCorp s authorized territory in Converse County through a regulatory recovery fee
FERC FORM NO.ED. 12-96 Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
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IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
payment that Kennecott Energy Company will make to PacifiCorp. The regulatory recovery fee protects other Wyoming customers
from any impacts due to the loss of the mine load. Powder River Energy Corporation will be the sole energy provider to the mine.
Washington
In December 2003, PacifiCorp filed with the Washington Utilities and Transportation Committee (the "WUTC") for a general rate
increase of $26.7 million annually, or 13.5%. In addition, PacifiCorp requested that the WUTC adopt the findings of a prudence
review of generating resources acquired since the last Washington general rate case. In August 2004, PacifiCorp entered into a
Settlement Agreement with the WUTC Staff and the ~ atural Resources Defense Council that recommended a $15.5 million annual
increase, or 7.8%. On October 27, 2004, the WUTC issued an order adopting the multi-party Settlement Agreement with limited
conditions resulting in a total rate increase of $15.1 million, or 7.5%, effective November 16,2004. On November 10,2004, the
WUTC issued a supplemental order with revised calculations. As a result, the WUTC authorized an annual increase of $15.5 million,
or 7., effective November 16,2004.
PacifiCorp filed an application in March 2005, for the deferral of higher power costs in 2005 due to poor hydroelectric conditions over
the past five years. PacifiCorp seeks deferral of these costs to track and preserve them for later incorporation in rates, to be considered
as part of PacifiCorp' s next Washington general rate case proceeding, anticipated to be filed in spring 2005. PacifiCorp requested that
the deferral continue through the conclusion of that general rate proceeding. As part of that proceeding, PacifiCorp expects to address
the rate treatment of the current low hydroelectric trend and power cost volatility through a proposed power cost adjustment
mechanism. It is anticipated that deferral of hydroelectric impacts can be discontinued at the conclusion of that proceeding and
replaced with a power cost adjustment mechanism that would address hydroelectric variability thereafter.
Idaho
In December 2003, PacifiCorp filed with the Idaho Public Utility Commission (the "IPUC") to recover Idaho s portion of income tax
payments resulting from Internal Revenue Service audits of prior years. In April 2004, the IPUC staff held public input meetings
concerning PacifiCorp' s application. A stipulated agreement signed by the parties was filed with the IPUC in May 2004 and was
approved by the IPUC in June 2004. This allowed recovery of $4.2 million over 16 months beginning in June 2004 when a power cost
recovery surcharge, which began in June 2002, expired.
On January 14,2005, PacifiCorp filed a general rate case with the IPUC related to continuing investment to serve Idaho load, increases
in employee-related costs and general inflation impacts. PacifiCorp seeks an increase of $15.1 million annually, or 12.5%. If approved
by the IPUC, new rates would take effect September 16,2005. On that date, unrelated surcharges currently in effect will expire, so the
net effect to customers of this increase would be $11.4 million annually, or 9.2% overall.
On January 28 2005, the IPUC approved PacifiCorp s application to reduce the Bonneville Power Administration (the "BPA") credit
effective January 31 2005. The reduction in the credit is necessary because PacifiCorp paid out $6.8 million more in credits to
residential and small-farm customers than it received from the BPA. The change will result in an 8.0% reduction in the credit given to
residential customers and a 20.5% reduction in the credit given small-farm customers. Changes in the level ofthe BPA credit affect the
net electricity costs to customers but do not impact PacifiCorp s results of operations or earnings.
Multi-State Process
The Multi-State Process commenced in April 2002 and is a collaborative process with stakeholders from each of the six states
PacifiCorp serves. The project's focus is to design, develop and implement a cost allocation methodology that achieves a more
permanent consensus on each states responsibility for the costs and benefits of PacifiCorp s existing assets, enables PacifiCorp to
recover the cost of future investments, and provides states with the ability to independently implement state energy policy objectives.
A number of collaborative meetings and conferences occurred during 2002 and 2003, which concluded in the development of the
Protocol" cost allocation methodology proposaL The Protocol was filed with each of the state commissions in Utah, Oregon
Wyoming and Idaho in September 2003 and in Washington in December 2003. Following discussions with all parties, this proposal
was further refined and re-submitted to each of the state commissions as the "Revised Protoco1."
FERC FORM NO.ED. 12-Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubm ission 04/25/2005 2004/04
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
During June 2004 through November 2004, settlement discussions occurred in each of the states; agreements were reached with
parties; and hearings or oral arguments took place. Final ratification of the Revised Protocol occurred in March 2005 with each of the
state commissions in Utah, Oregon, Wyoming and Idaho issuing orders approving and accepting the use of the Revised Protocol cost
allocation methodology for future rate setting in each of those states. In accordance with this agreement, ongoing rate case filings in
Oregon and Idaho have been based on the Revised Protocol and the recent Utah settlement was based on Revised Protocol. In
Washington, the WUTC issued its formal order approving and adopting the Washington general rate case settlement, accepting the
Revised Protocol for reporting purposes and establishing a process for ongoing discussions for a permanent allocation methodology
during fiscal 2006. The Revised Protocol has not yet been filed in the state of California.
LEGAL PROCEEDINGS
In May 2004, PacifiCorp was served with a complaint filed in the United States District Court for the District of Oregon by the
Klamath Tribes of Oregon, individual Klamath Tribal members and the Klamath Claims Committee. The claim generally alleges that
PacifiCorp and its predecessors affected the Klamath Tribes' federal treaty rights to fish for salmon in the headwaters of the Klamath
River in southern Oregon by building dams that blocked the passage of salmon upstream to the headwaters beginning in 1911. In July
2004, PacifiCorp filed its answer to the complaint. In September 2004, the case was transferred to the Medford Division of the District
of Oregon. Also in September 2004, the Klamath Tribes filed their first amended complaint adding claims of damage to their treaty
rights to fish for sucker and steelhead in the headwaters of the Klamath River. The claim seeks in excess of $1.0 billion in
compensatory and punitive damages. In October 2004, PacifiCorp filed its answer to the first amended complaint generally denying
liability and asserting affirmative defenses for the matters alleged by the Klamath Tribes. A scheduling conference was held in October
2004, which established a procedural schedule for the case. In February 2005, PacifiCorp filed a motion for summary judgment
seeking dismissal of the Klamath Tribe s case as untimely under the applicable statute of limitations. Oral argument on the motion for
summary judgment was held on April 12, 2005. On April 14, 2005, the magistrate judge issued an opinion recommending that
PacifiCorp s motion for summary judgment be granted and the case be dismissed as untimely. Parties have until May 3, 2005 to file
objections to the recommendation. The final order will be subject to appeal.
From time to time, PacifiCorp is also a party to various other legal claims, actions and complaints, certain of which seek significant
amounts. Although PacifiCorp is unable to predict with certainty whether it will ultimately be successful in these legal proceedings or,
if not, what the impact might be, management currently believes that disposition of these matters will not have a material adverse effect
on PacifiCorp s consolidated financial position or results of operations.
For a further discussion on legal proceeding, See Notes to the Financial Statements - Note 7 - Commitments and Contingencies, and
Note 9 - Income Taxes of this Form No. I.
ITEM 10.
For a discussion on related party transactions, see Notes to the Financial Statements - Note 4 - Related-Party Transactions of this Form
No.
ITEM 11.
(Reserved)
ITEM 12.
Integrated Resource Plan
As required by state regulators, PacifiCorp uses an Integrated Resource Plans to provide a framework and plan for prudent future
actions required to help ensure that PacifiCorp continues to provide reliable and cost-effective electric service to its customers. The
Integrated Resource Plan process identifies PacifiCorp s anticipated future resource mix in a coordinated process with the stakeholders
in each of the six states where PacifiCorp operates.
FERC FORM NO.ED. 12-96 Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
IMPORTANT CHANGES DURING THE OUARTERNEAR (Continued)
PacifiCorp published its 2003 Integrated Resource Plan in January 2003 and updated it in October 2003. PacifiCorp has segregated its
2003 Integrated Resource Plan supply-side action items into a series of separate Requests for Proposals, each of which focuses on a
specific category of supply-side resources and provides for the staged procurement of resources in future years in an attempt to
achieve load/resource balance. The outstanding Requests for Proposals are discussed below.
PacifiCorp filed its 2004 Integrated Resource Plan with the relevant state commissions in January 2005. Dockets have been established
in Utah, Oregon, Idaho and Washington to determine acknowledgment of the plan. The 2004 Integrated Resource Plan provides a
framework and plan for the prudent future actions required to ensure that PacifiCorp continues to provide reliable and cost-effective
electric service to its customers. Projected growth rates and contract expirations indicate a need for approximately 2,800 MW of
additional resources by 2015. These estimates are subject to ongoing review and revision. The Integrated Resource Plan process
identifies PacifiCorp s anticipated future resource mix in a coordinated process with the stakeholders in each of the six states where
PacifiCorp operates.
As part of the 2004 Integrated Resource Plan process, PacifiCorp has identified an electricity generation resource deficit and plans to
meet the resource deficit through a combination of the following sources: thermal generation (2 629 MW) and load control programs
(177 MW). PacifiCorp also plans to implement energy conservation programs (450 average MW) and will continue to procure 1,400
MW of economic renewable resources that were first identified in the 2003 Integrated Resource Plan. PacifiCorp intends to utilizes
wholesale electricity transactions to balance the remaining difference between retail load obligations and available resources, and to
optimize physical assets and minimize cost.
Requests for Proposals
RFP 2003A - To ensure an adequate supply to meet future energy needs, in May 2004, PacifiCorp entered into an asset purchase and
sale agreement with Summit Vineyard LLC of Denver, Colorado, to develop and, with Siemens Westinghouse Power Corporation, to
construct, a natural gas-fired combined-cycle combustion turbine electricity plant near Orem, Utah. The plant, to be known as the Lake
Side Power Plant and to have a summer rated capacity of 534 MW, was identified as the best option submitted through PacifiCorp
competitive RFP 2003A process of a resource to be made available by summer 2007. In May 2004, PacifiCorp filed with UPSC for a
Certificate of Convenience and Necessity. Hearings were held in October 2004 and the UPSC granted a Certificate of Public
Convenience and Necessity in November 2004. In October 2004, PacifiCorp entered into a long-term agreement with Siemens
Westinghouse Power Corporation for certain maintenance items on the Lake Side Power Plant and issued a limited notice to proceed
with construction preparation. The air quality permit for the Lake Side Power Plant was issued in January 2005. The Interconnection
Agreement between Summit Vineyard LLC and PacifiCorp was signed in March 2005. The Notice to Proceed between Summit
Vineyard LLC and Siemens Westinghouse Power Corporation was issued in March 2005. PacifiCorp has finalized the Transportation
Service Agreement for the construction of the gas lateral. The Lake Side Power Plant is expected to cost approximately $347.0 million.
Recovery of PacifiCorp s investment in the plant will be reviewed by the states PacifiCorp serves as part of future general rate cases.
RFP 2003B - PacifiCorp s 2003 Integrated Resource Plan identified 1,400 MW of renewable resources as part of a least cost portfolio
of resources to meet PacifiCorp s growing demand over a ten-year period. PacifiCorp issued a Renewable Request for Proposals in
February 2004 for up to 1,100 MW of economic renewable resources for PacifiCorp s system, which would come on line over the next
seven years. To date PacifiCorp has entered into a 64.5 MW power purchase agreement, to be on line prior to calendar 2006, for the
output of a wind farm located in southeastern Idaho. PacifiCorp is continuing to negotiate with other counterparties.
Bll 2009 (formerl.lflFP 2004Jti - PacifiCorp expects to issue a third Request for Proposals following a review of the results from
RFP 2003A and RFP 2003B and a new load/resource balance determination. PacifiCorp anticipates that it will issue RFP 2009 in
calendar 2005, requesting additional resources to serve PacifiCorp s growing load obligation. Utah Senate Bill 26, which became law
in February 2005, provides PacifiCorp a process to obtain pre-approval of related assets and/or power purchase agreements. Based on
PacifiCorp s Integrated Resource Plan, PacifiCorp expects that it will procure additional resources that can be delivered in or to
PacifiCorp s service territory in Utah, southwest Wyoming and southeast Idaho.
Demand-side RFP - In addition to the three supply-side Requests for Proposals, PacifiCorp issued a separate Request for Proposals
for the demand-side resources called for in its 2003 Integrated Resource Plan. The demand-side Request for Proposals was issued in
FERC FORM NO.ED. 12-96 Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
June 2003 and requested an additional 100 MW or more of conservation to be obtained over the next 10 years and load control
proposals specifically addressing peak load. Two conservation programs and one load control program were selected. Tariffs for each
program have been filed with the UPSc.
Regional Transmission Entity
PacifiCorp, in conjunction with other western utilities (the filing utilities), is seeking to develop an independent regional transmission
entity that would manage certain operational functions of the transmission grid and plan for necessary expansion. A non-profit
corporation has been established, known as Grid West (previously known as RTO West), and in December 2004, the filing utilities, in
collaboration with regional stakeholders, adopted new bylaws for Grid West's interim board, on which PacifiCorp has a representative.
During the remainder of calendar 2005, the activities for Grid West are expected to include the continued development of the regional
proposal for Grid West, initiating the process for parties to become members of the new Grid West organization and starting the search
for candidates to be elected as independent members of a new five-person developmental board of directors.
Assuming continued regional support, the filing utilities also plan to begin working with the proposed Grid West independent board of
trustees to develop transmission agreements and develop a Grid West tariff in calendar 2006.
The filing utilities have also entered into a Memorandum of Understanding with the other two potential western Regional Transmission
Organizations, namely WestConnect and the California Independent System Operator, and anticipates continued work on inter-regional
issues through this agreement or a redefined forum to address transmission and related market issues throughout the western
interconnection.
In addition to the Grid West activities, PacifiCorp is involved in two sub-regional planning efforts: the Rocky Mountain Area
Transmission Study and the Northwest Transmission Assessment Committee. These planning efforts are producing economic and
technical studies that focus on identifying specific economically desirable transmission expansions to support new generation to meet
growing consumer demands in the West. A broad range of stakeholders are also involved in this public process to identify the most
critical electric transmission and generation project needs. The sub-regional planning processes provide a framework for regional
collaboration to improve the western interconnection with technically, financially and environmentally viable transmission projects.
The sub-regional activities and Grid West activities are compatible, and PacifiCorp actively supports and participates in both.
Fair Value of Derivatives
The following table shows the changes in the fair value of energy-related contracts qualifying as derivatives under SF AS No. 133 from
December 31, 2003, to December 31, 2004, segregated between derivative contracts held for trading and non-trading purposes, and
quantifies the reasons for the changes.
(Millions of dollars)
Net Regulatory
Asset (Liabilit Net asset
Tradin Non-Tradin (Liabilit ) (b:
Fair value of contracts outstanding at December 31,2003
Contracts realized or otherwise settled during the period
Other changes in fair values (a)
(527.526.
(1.2)(0.(0.
256.(248.3)
(271.277.Fair value of contracts outstanding at December 31 2004
(a) Effective September 30, 2004, PacifiCorp changed to a U.S. London Interbank Offered Rate (LIB OR) rate
from the U.S. Treasury rate for discounting the portfolio. This change had the effect of increasing the fair
value of non-trading contracts by $25.5 million, offset by a decrease in regulatory net assets by the same
amount. Other changes in fair values include the effects of this change, along with the effects of changes in
FERC FORM NO.ED. 12-96 Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
prices, inflation rates and interest rates, including those based on models, on new and existing contracts for
the twelve months ended December 31, 2004.
Contracts which have received commission approval for regulatory recovery are included as a Regulatory
Net Asset (Liability).
(b)
The fair value of derivative instruments is determined using forward price curves. Forward price curves represent PacifiCorp
estimates of the prices at which a buyer or seller could contract today for delivery or settlement of a commodity at future dates.
PacifiCorp bases its forward price curves on market price quotations when available and on internally developed and commercial
models with internal and external fundamental data inputs when market quotations are unavailable. In general, PacifiCorp estimates the
fair value of a contract by calculating the present value of the difference between the prices in the contract and the applicable forward
price curve. Price quotations for certain major electricity trading hubs are generally readily obtainable for the first three years and
therefore PacifiCorp s forward price curves for those locations and periods reflect observable market quotes. However, in the later
years or for locations that are less or not actively traded, PacifiCorp must develop forward price curves. For short-term contracts at less
actively traded locations, prices are modeled based on observed historical price relationships with actively traded locations. For
long-term contracts extending beyond three years, the forward price curve is based upon the use of a fundamentals model (cost-to-build
approach) due to the limited information available. Factors used in the fundamentals model include the forward prices for the
commodities used as fuel to generate electricity, the expected system heat rate (which measures the efficiency of electricity plants in
converting fuel to electricity) in the region where the purchase or sale takes place, and a fundamental forecast of expected spot prices
based on modeled supply and demand in the region. The assumptions in these models are critical since any changes to the assumptions
could have a significant impact on the fair value of the contract. Contracts with explicit or embedded optionality are valued by
separating each contract into its physical and financial forward and option components. Forward components are valued against the
appropriate forward price curve. The optionality is valued using a modified Black-Scholes model or a stochastic simulation (Monte
Carlo) approach. Each option component is modeled and valued separately using the appropriate forward price curve.
PacifiCorp s valuation models and assumptions are continuously updated to reflect current market information, and evaluation and
refinement of model assumptions are performed on a periodic basis.
The following table shows summarized information with respect to valuation techniques and contractual maturities of PacifiCorp
energy-related contracts qualifying as derivatives under SF AS No. 133 as of December 31, 2004.
Fair Value of Contracts at Period-End
(Millions of dollars)
Maturity
Less Than
I Year
Maturity
3 Years
Maturity
4- 5 Years
Maturity
in Excess
of 5 Years
Total Fair
Val~
Trading:
Prices based on quoted market prices from third-party sources
Prices based 0 n models and other valuation methods
Total trading
Non-trading:
Prices based 0 n quoted market prices from third-party sources
Prices based 0 n models and other valuation methods
$ (20.
54.
(21.0)
57.
2.1
(59.
$ 2.
(286.
$ (37.
(234.
Total non-trading 34.36.$ (57.$ (284.$ (271.5)
Standardized derivative contracts that are valued using market quotations are classified as "prices based on quoted market prices from
third-party sources." All remaining contracts, which include non-standard contracts and contracts for which market prices are not
routinely quoted, are classified as "prices based on models and other valuation methods.
For a further discussion on important changes during the year, See Notes to the Financial Statements of this Form No.
FERC FORM NO.ED. 12-Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
ITEM 13.
Please refer to pages 104 Officers and 105 Directors of this Form No.
ITEM 14.
FERC FORM NO.ED. 12-Page 109.
Blank Page
(Next Page is: 110)
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Da, Yr)
(2)A Resubmlssion 04/25/2005 End of 2004/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Current Year Prior YearLineRef.End of Quarter/Year End BalanceNo.Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
UTILITY PLANT
Utility Plant (101-106 114)200-201 13,871 234 077 13,391 609,608
Construction Work in Progress (107)200-201 439 891 117 340 357 627
TOTAL Utility Plant (Enter Total of lines 2 and 3)311 125,194 731 967 235
(Less) Accum. Provo for Depr. Amort. Depl. (108, 110, 111 , 115)200-201 860,338 93E 611 642 430
Net Utility Plant (Enter Total of line 4 less 5)450 786,258 120 324 805
Nuclear Fuel in Process of Ref., Conv.Enrich., and Fab. (120.202-203
Nuclear Fuel Materials and Assemblies-Stock Account (120.
Nuclear Fuel Assemblies in Reactor (120.
Spent Nuclear Fuel (120.
Nuclear Fuel Under Capital Leases (120.
(Less) Accum. Provo for Amort. of Nucl. Fuel Assemblies (120.202-203
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
Net Utility Plant (Enter Total of lines 6 and 13)8,450 786 258 120,324,805
Utility Plant Adjustments (116)122
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutility Property (121)217 226 695,360
(Less) Accum. Provo for Depr. and Amort. (122)1,491 696 030,977
Investments in Associated Companies (123)15,111 724 391 260
Investment in Subsidiary Companies (123.224-225 298,918 68,883,997
(For Cost of Account 123., See Footnote Page 224, line 42)
Noncurrent Portion of Allowances 228-229
Other Investments (124)85,964 600 354 345
Sinking Funds (125)
Depreciation Fund (126)
Amortization Fund - Federal (127)
Other Special Funds (128)10,833,026 302,481
Special Funds (Non Major Only) (129)
Long-Term Portion of Derivative Assets (175)247 045 401 155 826,566
Long-Term Portion of Derivative Assets - Hedges (176)
TOTAL Other Property and Investments (Lines 18-21 and 23-31)435 979 19S 327 423 032
CURRENT AND ACCRUED ASSETS
Cash and Working Funds (Non-major Only) (130)
Cash (131)336,089 172 905
Special Deposits (132-134)15,584 319
Working Fund (135)098 43,022
Temporary Cash Investments (136)854 734 590 389
Notes Receivable (141)425,229 871 655
Customer Accounts Receivable (142)290,118,180 280 155 319
Other Accounts Receivable (143)751 889 12,998,491
(Less) Accum. Provo for Uncollectible Acct.-Credit (144)18,937 480 564 131
Notes Receivable from Associated Companies (145)323 105
Accounts Receivable from Assoc. Companies (146)514,160 158,757
Fuel Stock (151)227 48,450 942 53,546,693
Fuel Stock Expenses Undistributed (152)227
Residuals (Elec) and Extracted Products (153)227
Plant Materials and Operating Supplies (154)227 105 246,617 91,550,850
Merchandise (155)227
Other Materials and Supplies (156)227
Nuclear Materials Held for Sale (157)202-203/227
Allowances (158.1 and 158.228-229
FERC FORM NO.1 (REV. 12-03)Page 110
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1)An Original (Mo, Oa, Yr)
(2)A Resubmission 04/25/2005 End of 2004/04
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)Continued)
Line
Current Year Prior Year
Ref.End of OuarterlYear End Balance
No.Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
(Less) Noncurrent Portion of Allowances
Stores Expense Undistributed (163)227
Gas Stored Underground - Current (164.
Liquefied Natural Gas Stored and Held for Processing (164.164.
Prepayments (165)26,647,642
Advances for Gas (166-167)
Interest and Dividends Receivable (171)58,070 582
Rents Receivable (172)441 927 813 746
Accrued Utility Revenues (173)158,191 000 150,791 505
Miscellaneous Current and Accrued Assets (174)282 313 862
Derivative Instrument Assets (175)367,444 527 253,211 896
(Less) Long-Term Portion of Derivative Instrument Assets (175)247,045,401 155,826 566
Derivative Instrument Assets - Hedges (176)
(Less) long-Term Portion of Derivative Instrument Assets - Hedges (176
Total Current and Accrued Assets (Lines 34 through 66)833,023,058 770,397 954
DEFERRED DEBITS
Unamortized Debt Expenses (181)306 627 580,785
Extraordinary Property losses (182.230
Unrecovered Plant and Regulatory Study Costs (182.230 16,818 879 23,797 847
Other Regulatory Assets (182.232 191 062 740 573,981 490
Prelim. Survey and Investigation Charges (Electric) (183)501 867 459,800
Preliminary Natural Gas Survey and Investigation Charges 183.
Other Preliminary Survey and Investigation Charges (183.
Clearing Accounts (184)10,469 123,677
Temporary Facilities (185)111 912
Miscellaneous Deferred Debits (186)233 78,628,533 695,115
Def. Losses from Disposition of Utility PIt. (187)
Research, Devel. and Demonstration Expend. (188)352-353
Unamortized Loss on Reaquired Debt (189)36,402,630 398,006
Accumulated Deferred Income Taxes (190)234 55,788,505
Unrecovered Purchased Gas Costs (191)
Total Deferred Debits (lines 69 through 83)117 749,320 817,883,137
TOTAL ASSETS (lines 14-16,32,, and 84)837.537,835 036,028,928
FERC FORM NO.1 (REV. 12-03)Page 111
..----...-- --------.- '-'----"~'---~
Name of Respondent This Report is:Date of Report Year/Period of Report
PacifiCorp (1)An Original (mo, dB, yr)
(2)A Rresubmission 04/25/2005 end of 2004/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line Current Year Prior Year
Ref.End of Ouarter/Y ear End BalanceNo.Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
PROPRIETARY CAPITAL
Common Stock Issued (201)250-251 933,226 675 933 226 675
Preferred Stock Issued (204)250-251 41,463,300 41 ,463,300
Capital Stock Subscribed (202, 205)252
Stock Liability for Conversion (203, 206)252
Premium on Capital Stock (207)252
Other Paid-In Capital (208-211)253 59,808
Installments Received on Capital Stock (212)252
(Less) Discount on Capital Stock (213)254
(Less) Capital Stock Expense (214)254 281 084 281 084
Retained Earnings (215, 215., 216)118-119 070 214 448 029,270 144
Unappropriated Undistributed Subsidiary Earnings (216.118-119 662 613 084 664,367,224
(Less) Reaquired Capital Stock (217)250-251
Noncorporate Proprietorship (Non-major only) (218)
Accumulated Other Comprehensive Income (219)122(a)(b)989,643 955,259
Total Proprietary Capital (lines 2 through 15)333,080,420 296,356,552
LONG-TERM DEBT
Bonds (221)256-257 880,571,649 764 569 610
(Less) Reaquired Bonds (222)256-257
Advances from Associated Companies (223)256-257
Other Long-Term Debt (224)256-257 500,000 60,000,000
Unamortized Premium on Long-Term Debt (225)49,154 51,872
(Less) Unamortized Discount on Long-Term Debt-Debit (226)989,338 535,780
Total Long-Term Debt (lines 18 through 23)928,131 465 820,085,702
OTHER NONCURRENT LIABILITIES
Obligations Under Capital Leases - Noncurrent (227)26,452 853 462 560
Accumulated Provision for Property Insurance (228.268,271 742 390
Accumulated Provision for Injuries and Damages (228.919,934 230,424
Accumulated Provision for Pensions and Benefits (228.382 512 888 430 367 542
Accumulated Miscellaneous Operating Provisions (228.4)585 027 054 337
Accumulated Provision for Rate Refunds (229)779
Long-Term Portion of Derivative Instrument Liabilities 552 527 026 684 070 675
Long-Term Portion of Derivative Instrument Liabilities - Hedges
Asset Retirement Obligations (230)66,683,967 65,056 481
Total Other Noncurrent Liabilities (lines 26 through 34)066,950,745 224 984 409
CURRENT AND ACCRUED LIABILITIES
Notes Payable (231)285 000,000 225,000 000
Accounts Payable (232)297 246,335 271 890,617
Notes Payable to Associated Companies (233)570,776 608,243
Accounts Payable to Associated Companies (234)16,726,512 12,757 417
Customer Deposits (235)581 709 20,952,162
Taxes Accrued (236)262-263 31,604,016 37,718,526
Interest Accrued (237)54,552,956 55,045,018
Dividends Declared (238)520,947 520,947
Matured Long-Term Debt (239)
FERC FORM NO.1 (rev. 12-03)Page 112
Name of Respondent This Report is:Date of Report Year/Period of Report
PacifiCorp (1)An Original (mo, dB, yr)
(2)A Rresubmission 04/25/2005 end of 2004/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITlS)ntinued)
Line
Current Year Prior Year
No.
Ref.End of OuarterlYear End Balance
Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
Matured Interest (240)
Tax Collections Payable (241)10,775,84S 695 787
Miscellaneous Current and Accrued Liabilities (242)73,274 69:3 279,890
Obligations Under Capital Leases-Current (243)160 550 158,833
Derivative Instrument Liabilities (244)638,689,025 779,667,712
(Less) Long-Term Portion of Derivative Instrument Liabilities 552 527 026 684,070,675
Derivative Instrument Liabilities - Hedges (245)
(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
Total Current and Accrued Liabilities (lines 37 through 53)898,176,342 812,224,477
DEFERRED CREDITS
Customer Advances for Construction (252)181 457 820,064
Accumulated Deferred Investment Tax Credits (255)266-267 528,180 85,448,300
Deferred Gains from Disposition of Utility Plant (256)
Other Deferred Credits (253)269 58,618,828 59,731 246
Other Regulatory Liabilities (254)278 128,575,966 142 523,028
Unamortized Gain on Reaquired Debt (257)225,690 311,142
Accum. Deferred Income Taxes-Accel. Amort.(281)272-277 968,392,714
Accum. Deferred Income Taxes-Other Property (282)626,481 774
Accum. Deferred Income Taxes-Other (283)330,480
Total Deferred Credits (lines 56 through 64)611 198,863 882 377,788
TOTAL LIABILITIES AND STOCKHOLDER EOUITY (lines 16,24,35,54 and 65)837,537,835 036,028 928
FERC FORM NO.1 (rev. 12-03)Page 113
----
Name of Respondent This i!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
STATEMENT OF INCOME
1. Enter in column (e) operations for the reporting quarter and in column (f) the operations for the same three month period for the prior
year.
2. Report in Column (g) year to date amounts for electric utility function; in column (i) the year to date amounts for gas utility, and in (k)
the year to date amounts for the other utility function for the current quarter/year.
3. Report in Column (h) year to date amounts for electric utility function; in column (j) the year to date amounts for gas utility, and in (I)
the year to date amounts for the other utility function for the previous quarter/year.
4. If additional columns are needed place them in a footnote.
Line Total Total Current 3 Months Prior 3 Months
No.Current Year to Prior Year to Ended Ended
(Ref.)Date Balance for Date Balance for Quarterly Only Quarterly Only
Title of Account Page No.QuarterN ear QuarterNear No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(ij
UTILITY OPERATING INCOME
Operating Revenues (400)300-301 989 584 939 533 716 464
Operating Expenses
Operation Expenses (401)320-323 580,818,240 099,586,984
Maintenance Expenses (402)320-323 314659,283 262 191 746
Depreciation Expense (403)336-337 360,452 077 356,099 545
Depreciation Expense for Asset Retirement Costs (403.336-337
Amort. & Depl. of Utility Plant (404-405)336-337 52,530,998 53,952,761
Amort. of Utility Plant Acq. Adj. (406)336-337 479 353 479 353
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
Amort. of Conversion Expenses (407)
Regulatory Debits (407.961 370 872 701
(Less) Regulatory Credits (407.477 020 510
Taxes Other Than Income Taxes (408.262.263 105,934 524
Income Taxes - Fedefal (409.262-263 113,289,157
- Other (409.262-263 13,196,799
Provision for Deferred Income Taxes (410.234, 272-277 715,726 978 228,862,158
(Less) Provision for Deferred Income Taxes-Cr. (411.234, 272-277 625,131 917 169 961 205
Investment Tax Credit Adj. - Net (411.266 854 859 940,091
(Less) Gains from Disp. of Utility Plant (411.
Losses from Disp. of Utility Plant (411.
(Less) Gains from Disposition of Allowances (411.908,181 585,037
Losses from Disposition of Allowances (411.
Accretion Expense (411.10)
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)530 493,011 067 999,905
Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117 line 27 459,091,928 465,716,559
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114
Name of Respondent This i!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
STATEMENT OF INCOME
1. Enter in column (e) operations for the reporting quarter and in column (f) the operations for the same three month period for the prior
year.
2. Report in Column (g) year to date amounts for electric utility function; in column (i) the year to date amounts for gas utility, and in (k)
the year to date amounts for the other utility function for the current quarter/year.
3. Report in Column (h) year to date amounts for electric utility function; in column (j) the year to date amounts for gas utility, and in (I)
the year to date amounts for the other utility function for the previous quarter/year.
4. If additional columns are needed place them in a footnote.
Line Total Total Current 3 Months Prior 3 Months
No.Current Year to Prior Year to Ended Ended
(Ref.)Date Balance for Date Balance for Quarterly Only Quarterly Only
Title of Account Page No.QuarterN ear QuarterNear No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(ij
UTILITY OPERATING INCOME
Operating Revenues (400)300-301 989 584 939 533 716 464
Operating Expenses
Operation Expenses (401)320-323 580,818,240 099,586,984
Maintenance Expenses (402)320-323 314659,283 262 191 746
Depreciation Expense (403)336-337 360,452 077 356,099 545
Depreciation Expense for Asset Retirement Costs (403.336-337
Amort. & Depl. of Utility Plant (404-405)336-337 52,530,998 53,952,761
Amort. of Utility Plant Acq. Adj. (406)336-337 479 353 479 353
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
Amort. of Conversion Expenses (407)
Regulatory Debits (407.961 370 872 701
(Less) Regulatory Credits (407.477 020 510
Taxes Other Than Income Taxes (408.262.263 105,934 524
Income Taxes - Fedefal (409.262-263 113,289,157
- Other (409.262-263 13,196,799
Provision for Deferred Income Taxes (410.234, 272-277 715,726 978 228,862,158
(Less) Provision for Deferred Income Taxes-Cr. (411.234, 272-277 625,131 917 169 961 205
Investment Tax Credit Adj. - Net (411.266 854 859 940,091
(Less) Gains from Disp. of Utility Plant (411.
Losses from Disp. of Utility Plant (411.
(Less) Gains from Disposition of Allowances (411.908,181 585,037
Losses from Disposition of Allowances (411.
Accretion Expense (411.10)
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)530 493,011 067 999,905
Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117 line 27 459,091,928 465,716,559
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114
Name of Respondent This i!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
STATEMENT OF INCOME
1. Enter in column (e) operations for the reporting quarter and in column (f) the operations for the same three month period for the prior
year.
2. Report in Column (g) year to date amounts for electric utility function; in column (i) the year to date amounts for gas utility, and in (k)
the year to date amounts for the other utility function for the current quarter/year.
3. Report in Column (h) year to date amounts for electric utility function; in column (j) the year to date amounts for gas utility, and in (I)
the year to date amounts for the other utility function for the previous quarter/year.
4. If additional columns are needed place them in a footnote.
Line Total Total Current 3 Months Prior 3 Months
No.Current Year to Prior Year to Ended Ended
(Ref.)Date Balance for Date Balance for Quarterly Only Quarterly Only
Title of Account Page No.QuarterN ear QuarterNear No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(ij
UTILITY OPERATING INCOME
Operating Revenues (400)300-301 989 584 939 533 716 464
Operating Expenses
Operation Expenses (401)320-323 580,818,240 099,586,984
Maintenance Expenses (402)320-323 314659,283 262 191 746
Depreciation Expense (403)336-337 360,452 077 356,099 545
Depreciation Expense for Asset Retirement Costs (403.336-337
Amort. & Depl. of Utility Plant (404-405)336-337 52,530,998 53,952,761
Amort. of Utility Plant Acq. Adj. (406)336-337 479 353 479 353
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
Amort. of Conversion Expenses (407)
Regulatory Debits (407.961 370 872 701
(Less) Regulatory Credits (407.477 020 510
Taxes Other Than Income Taxes (408.262.263 105,934 524
Income Taxes - Fedefal (409.262-263 113,289,157
- Other (409.262-263 13,196,799
Provision for Deferred Income Taxes (410.234, 272-277 715,726 978 228,862,158
(Less) Provision for Deferred Income Taxes-Cr. (411.234, 272-277 625,131 917 169 961 205
Investment Tax Credit Adj. - Net (411.266 854 859 940,091
(Less) Gains from Disp. of Utility Plant (411.
Losses from Disp. of Utility Plant (411.
(Less) Gains from Disposition of Allowances (411.908,181 585,037
Losses from Disposition of Allowances (411.
Accretion Expense (411.10)
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)530 493,011 067 999,905
Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117 line 27 459,091,928 465,716,559
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114
Name of Respondent This i!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
STATEMENT OF INCOME
1. Enter in column (e) operations for the reporting quarter and in column (f) the operations for the same three month period for the prior
year.
2. Report in Column (g) year to date amounts for electric utility function; in column (i) the year to date amounts for gas utility, and in (k)
the year to date amounts for the other utility function for the current quarter/year.
3. Report in Column (h) year to date amounts for electric utility function; in column (j) the year to date amounts for gas utility, and in (I)
the year to date amounts for the other utility function for the previous quarter/year.
4. If additional columns are needed place them in a footnote.
Line Total Total Current 3 Months Prior 3 Months
No.Current Year to Prior Year to Ended Ended
(Ref.)Date Balance for Date Balance for Quarterly Only Quarterly Only
Title of Account Page No.QuarterN ear QuarterNear No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(ij
UTILITY OPERATING INCOME
Operating Revenues (400)300-301 989 584 939 533 716 464
Operating Expenses
Operation Expenses (401)320-323 580,818,240 099,586,984
Maintenance Expenses (402)320-323 314659,283 262 191 746
Depreciation Expense (403)336-337 360,452 077 356,099 545
Depreciation Expense for Asset Retirement Costs (403.336-337
Amort. & Depl. of Utility Plant (404-405)336-337 52,530,998 53,952,761
Amort. of Utility Plant Acq. Adj. (406)336-337 479 353 479 353
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
Amort. of Conversion Expenses (407)
Regulatory Debits (407.961 370 872 701
(Less) Regulatory Credits (407.477 020 510
Taxes Other Than Income Taxes (408.262.263 105,934 524
Income Taxes - Fedefal (409.262-263 113,289,157
- Other (409.262-263 13,196,799
Provision for Deferred Income Taxes (410.234, 272-277 715,726 978 228,862,158
(Less) Provision for Deferred Income Taxes-Cr. (411.234, 272-277 625,131 917 169 961 205
Investment Tax Credit Adj. - Net (411.266 854 859 940,091
(Less) Gains from Disp. of Utility Plant (411.
Losses from Disp. of Utility Plant (411.
(Less) Gains from Disposition of Allowances (411.908,181 585,037
Losses from Disposition of Allowances (411.
Accretion Expense (411.10)
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)530 493,011 067 999,905
Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117 line 27 459,091,928 465,716,559
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114
Name of Respondent This i!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
STATEMENT OF INCOME
1. Enter in column (e) operations for the reporting quarter and in column (f) the operations for the same three month period for the prior
year.
2. Report in Column (g) year to date amounts for electric utility function; in column (i) the year to date amounts for gas utility, and in (k)
the year to date amounts for the other utility function for the current quarter/year.
3. Report in Column (h) year to date amounts for electric utility function; in column (j) the year to date amounts for gas utility, and in (I)
the year to date amounts for the other utility function for the previous quarter/year.
4. If additional columns are needed place them in a footnote.
Line Total Total Current 3 Months Prior 3 Months
No.Current Year to Prior Year to Ended Ended
(Ref.)Date Balance for Date Balance for Quarterly Only Quarterly Only
Title of Account Page No.QuarterN ear QuarterNear No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(ij
UTILITY OPERATING INCOME
Operating Revenues (400)300-301 989 584 939 533 716 464
Operating Expenses
Operation Expenses (401)320-323 580,818,240 099,586,984
Maintenance Expenses (402)320-323 314659,283 262 191 746
Depreciation Expense (403)336-337 360,452 077 356,099 545
Depreciation Expense for Asset Retirement Costs (403.336-337
Amort. & Depl. of Utility Plant (404-405)336-337 52,530,998 53,952,761
Amort. of Utility Plant Acq. Adj. (406)336-337 479 353 479 353
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
Amort. of Conversion Expenses (407)
Regulatory Debits (407.961 370 872 701
(Less) Regulatory Credits (407.477 020 510
Taxes Other Than Income Taxes (408.262.263 105,934 524
Income Taxes - Fedefal (409.262-263 113,289,157
- Other (409.262-263 13,196,799
Provision for Deferred Income Taxes (410.234, 272-277 715,726 978 228,862,158
(Less) Provision for Deferred Income Taxes-Cr. (411.234, 272-277 625,131 917 169 961 205
Investment Tax Credit Adj. - Net (411.266 854 859 940,091
(Less) Gains from Disp. of Utility Plant (411.
Losses from Disp. of Utility Plant (411.
(Less) Gains from Disposition of Allowances (411.908,181 585,037
Losses from Disposition of Allowances (411.
Accretion Expense (411.10)
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)530 493,011 067 999,905
Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117 line 27 459,091,928 465,716,559
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114
Name of Respondent This i!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
STATEMENT OF INCOME
1. Enter in column (e) operations for the reporting quarter and in column (f) the operations for the same three month period for the prior
year.
2. Report in Column (g) year to date amounts for electric utility function; in column (i) the year to date amounts for gas utility, and in (k)
the year to date amounts for the other utility function for the current quarter/year.
3. Report in Column (h) year to date amounts for electric utility function; in column (j) the year to date amounts for gas utility, and in (I)
the year to date amounts for the other utility function for the previous quarter/year.
4. If additional columns are needed place them in a footnote.
Line Total Total Current 3 Months Prior 3 Months
No.Current Year to Prior Year to Ended Ended
(Ref.)Date Balance for Date Balance for Quarterly Only Quarterly Only
Title of Account Page No.QuarterN ear QuarterNear No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(ij
UTILITY OPERATING INCOME
Operating Revenues (400)300-301 989 584 939 533 716 464
Operating Expenses
Operation Expenses (401)320-323 580,818,240 099,586,984
Maintenance Expenses (402)320-323 314659,283 262 191 746
Depreciation Expense (403)336-337 360,452 077 356,099 545
Depreciation Expense for Asset Retirement Costs (403.336-337
Amort. & Depl. of Utility Plant (404-405)336-337 52,530,998 53,952,761
Amort. of Utility Plant Acq. Adj. (406)336-337 479 353 479 353
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
Amort. of Conversion Expenses (407)
Regulatory Debits (407.961 370 872 701
(Less) Regulatory Credits (407.477 020 510
Taxes Other Than Income Taxes (408.262.263 105,934 524
Income Taxes - Fedefal (409.262-263 113,289,157
- Other (409.262-263 13,196,799
Provision for Deferred Income Taxes (410.234, 272-277 715,726 978 228,862,158
(Less) Provision for Deferred Income Taxes-Cr. (411.234, 272-277 625,131 917 169 961 205
Investment Tax Credit Adj. - Net (411.266 854 859 940,091
(Less) Gains from Disp. of Utility Plant (411.
Losses from Disp. of Utility Plant (411.
(Less) Gains from Disposition of Allowances (411.908,181 585,037
Losses from Disposition of Allowances (411.
Accretion Expense (411.10)
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)530 493,011 067 999,905
Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117 line 27 459,091,928 465,716,559
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04
(2) n A Resubmission 04/25/2005
STATEMENT OF INCOME FOR THE YEAR (Continued)
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY
Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Current Year to lJate PrevIous Year to Date Line
(in dollars)(in dollars)(in dollars)(in dollars)(in dollars)(in dollars)No.
(9)(h)(i)(k)(I)
533,716,464
099,586,984
314 659 283 262 191 746
356,099,545
530 998 53,952 761
479,353 479,353
961 370 872 701
2,477 020,510
105,934,524
45,160,095 113,289,157
313,742 13,196,799
228,862,158
p;~~~:;~~~
169,961,205
854 859 940,091
908,181 585,037
530,493,011 067 999,905
459,091,928 465,716,559
FERC FORM NO.1 (ED. 12-96)Page 115
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04
(2) n A Resubmission 04/25/2005
STATEMENT OF INCOME FOR THE YEAR (Continued)
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY
Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Current Year to lJate PrevIous Year to Date Line
(in dollars)(in dollars)(in dollars)(in dollars)(in dollars)(in dollars)No.
(9)(h)(i)(k)(I)
533,716,464
099,586,984
314 659 283 262 191 746
356,099,545
530 998 53,952 761
479,353 479,353
961 370 872 701
2,477 020,510
105,934,524
45,160,095 113,289,157
313,742 13,196,799
228,862,158
p;~~~:;~~~
169,961,205
854 859 940,091
908,181 585,037
530,493,011 067 999,905
459,091,928 465,716,559
FERC FORM NO.1 (ED. 12-96)Page 115
Name of Respondent This i!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
STATEMENT OF INCOME
1. Enter in column (e) operations for the reporting quarter and in column (f) the operations for the same three month period for the prior
year.
2. Report in Column (g) year to date amounts for electric utility function; in column (i) the year to date amounts for gas utility, and in (k)
the year to date amounts for the other utility function for the current quarter/year.
3. Report in Column (h) year to date amounts for electric utility function; in column (j) the year to date amounts for gas utility, and in (I)
the year to date amounts for the other utility function for the previous quarter/year.
4. If additional columns are needed place them in a footnote.
Line Total Total Current 3 Months Prior 3 Months
No.Current Year to Prior Year to Ended Ended
(Ref.)Date Balance for Date Balance for Quarterly Only Quarterly Only
Title of Account Page No.QuarterN ear QuarterNear No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(ij
UTILITY OPERATING INCOME
Operating Revenues (400)300-301 989 584 939 533 716 464
Operating Expenses
Operation Expenses (401)320-323 580,818,240 099,586,984
Maintenance Expenses (402)320-323 314659,283 262 191 746
Depreciation Expense (403)336-337 360,452 077 356,099 545
Depreciation Expense for Asset Retirement Costs (403.336-337
Amort. & Depl. of Utility Plant (404-405)336-337 52,530,998 53,952,761
Amort. of Utility Plant Acq. Adj. (406)336-337 479 353 479 353
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
Amort. of Conversion Expenses (407)
Regulatory Debits (407.961 370 872 701
(Less) Regulatory Credits (407.477 020 510
Taxes Other Than Income Taxes (408.262.263 105,934 524
Income Taxes - Fedefal (409.262-263 113,289,157
- Other (409.262-263 13,196,799
Provision for Deferred Income Taxes (410.234, 272-277 715,726 978 228,862,158
(Less) Provision for Deferred Income Taxes-Cr. (411.234, 272-277 625,131 917 169 961 205
Investment Tax Credit Adj. - Net (411.266 854 859 940,091
(Less) Gains from Disp. of Utility Plant (411.
Losses from Disp. of Utility Plant (411.
(Less) Gains from Disposition of Allowances (411.908,181 585,037
Losses from Disposition of Allowances (411.
Accretion Expense (411.10)
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)530 493,011 067 999,905
Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117 line 27 459,091,928 465,716,559
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114
Name of Respondent This i!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
STATEMENT OF INCOME
1. Enter in column (e) operations for the reporting quarter and in column (f) the operations for the same three month period for the prior
year.
2. Report in Column (g) year to date amounts for electric utility function; in column (i) the year to date amounts for gas utility, and in (k)
the year to date amounts for the other utility function for the current quarter/year.
3. Report in Column (h) year to date amounts for electric utility function; in column (j) the year to date amounts for gas utility, and in (I)
the year to date amounts for the other utility function for the previous quarter/year.
4. If additional columns are needed place them in a footnote.
Line Total Total Current 3 Months Prior 3 Months
No.Current Year to Prior Year to Ended Ended
(Ref.)Date Balance for Date Balance for Quarterly Only Quarterly Only
Title of Account Page No.QuarterN ear QuarterNear No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(ij
UTILITY OPERATING INCOME
Operating Revenues (400)300-301 989 584 939 533 716 464
Operating Expenses
Operation Expenses (401)320-323 580,818,240 099,586,984
Maintenance Expenses (402)320-323 314659,283 262 191 746
Depreciation Expense (403)336-337 360,452 077 356,099 545
Depreciation Expense for Asset Retirement Costs (403.336-337
Amort. & Depl. of Utility Plant (404-405)336-337 52,530,998 53,952,761
Amort. of Utility Plant Acq. Adj. (406)336-337 479 353 479 353
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
Amort. of Conversion Expenses (407)
Regulatory Debits (407.961 370 872 701
(Less) Regulatory Credits (407.477 020 510
Taxes Other Than Income Taxes (408.262.263 105,934 524
Income Taxes - Fedefal (409.262-263 113,289,157
- Other (409.262-263 13,196,799
Provision for Deferred Income Taxes (410.234, 272-277 715,726 978 228,862,158
(Less) Provision for Deferred Income Taxes-Cr. (411.234, 272-277 625,131 917 169 961 205
Investment Tax Credit Adj. - Net (411.266 854 859 940,091
(Less) Gains from Disp. of Utility Plant (411.
Losses from Disp. of Utility Plant (411.
(Less) Gains from Disposition of Allowances (411.908,181 585,037
Losses from Disposition of Allowances (411.
Accretion Expense (411.10)
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)530 493,011 067 999,905
Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117 line 27 459,091,928 465,716,559
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
STATEMENT OF INCOME FOR THE YEAR (continued)
Line TOTAL -C-urrent 3~onths Prior 3 Months
No.Ended Ended
(Ref.Quarterly Only Quarterly Only
Title of Account Page No.Current Year Previous Year No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)
Net Utility Operating Income (Carried forward from page 114)459 091 928 465 716 559
Other Income and Deductions
Other Income
Nonutilty Operating Income
Revenues From Merchandising, Jobbing and Contract Work (415)4,462,283 204,117
(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)205,149 361 265
Revenues From Nonutility Operations (417)617 651 913 107
(Less) Expenses of Nonutility Operations (417.793 13,237
Nonoperating Rental Income (418)009 53,633
Equity in Earnings of Subsidiary Companies (418.119 813 948 162,393
Interest and Dividend Income (419)853,797 832,492
Allowance for Other Funds Used During Construction (419.163,409 12,943,773
Miscellaneous Nonoperating Income (421)88,025,572 106,001,420
Gain on Disposition of Property (421.929,669 977 838
TOTAL Other Income (Enter Total of lines 31 thru 40)105,702,396 131 607005
Other Income Deductions
Loss on Disposition of Property (421.744 691 636,476
Miscellaneous Amortization (425)340 339,256 590049
Donations (426.340 854 177 602 016
Life Insurance (426.-8,495,975 10,697 837
Penalties (426.179,528 26,100
Exp. for Certain Civic, Political & Related Activities (426.717 717 553,310
Other Deductions (426.403 804 139 443,745
TOTAL Other Income Deductions (Total of lines 43 thru 49)73,743,198 141 153,659
Taxes Applic. to Other Income and Deductions
Taxes Other Than Income Taxes (408.262-263 193,371 349 138
Income Taxes-Federal (409.262-263 857 383
Income Taxes-Other (409.262-263 067,891 957 265
Provision for Deferred Inc. Taxes (410.234, 272-277 679,661
(Less) Provision for Deferred Income Taxes-Cr. (411.234, 272-277 226
Investment Tax Credit Adj.Net (411.
(Less) Investment Tax Credits (420)065,260 980 029
TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)346,756 611 997
Net Other Income and Deductions (Total of lines 41 , 50, 59)26,612,442 065 143
Interest Charges
Interest on Long-Term Debt (427)229,563,697 220,390,392
Amort. of Debt Disc. and Expense (428)4,404,847 670,074
Amortization of Loss on Reaquired Debt (428.291 370 022,423
(Less) Amort. of Premium on Debt-Credit (429)718 718
(Less) Amortization of Gain on Reaquired Debt-Credit (429.85,451 87,389
Interest on Debt to Assoc. Companies (430)340 426,708 19,714,053
Other Interest Expense (431)340 20,945,010 18,030,045
(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)767,217 8,432,882
Net Interest Charges (Total of lines 62 thru 69)255,776,246 260,303 998
Income Before Extraordinary Items (Total of lines 27 60 and 70)229 928,124 216,477,704
Extraordinary Items
Extraordinary Income (434)470 993
(Less) Extraordinary Deductions (435)
Net Extraordinary Items (Total of line 73 less line 74)470,993
Income Taxes-Federal and Other (409.262-263
Extraordinary Items After Taxes (line 75 less line 76)912,751
Net Income (Total of line 71 and 77)229,928,124 215,564 953
FERC FORM NO.1/3-a (REV. 02-04)Page 117
Blank Page
(Next Page is: 118)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings.Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Current Previous
OuarterN ear QuarterN ear
Contra Primary Year to Date Year to Date
Line Item Account Affected Balance Balance
No.(a)(b)(c)(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
Balance-Beginning of Period 025 694 333 936,324 910
Changes
Adjustments to Retained Earnings (Account 439)
TOTAL Credits to Retained Earnings (Acct. 439)
TOTAL Debits to Retained Earnings (Acct. 439)
Balance Transferred from Income (Account 433 less Account 418.228,114,174 214,402 560
Appropriations of Retained Earnings (Acct. 436)
TOTAL Appropriations of Retained Earnings (Acct. 436)
Dividends Declared-Preferred Stock (Account 437)
Preferred Dividends (Various Series and Rates)238 083 789 614 333)
TOTAL Dividends Declared-Preferred Stock (Acct. 437)083,789 614 333)
Dividends Declared-Common Stock (Account 438)
Common Dividends 238 185,086,081 120,418,804)
TOTAL Dividends Declared-Common Stock (Acct. 438)185,086,081 120,418,804)
Transfers from Acct 216., Unapprop. Undistrib. Subsidiary Earnings
Balance - End of Period (Total 1 ,15,29,36.37)066,638,637 025,694 333
FERC FORM NO. 1/3-Q (REV. 02-04)Page 118
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
Line
No.
Item
(a)
APPROPRIATED RETAINED EARNINGS (Account 215)
45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.
47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48 TOTAL Retained Eamings (Acct. 215,215.216) (Total 38, 47) (216.
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Ouarterly
49 Balance-Beginning of Year (Debit or Credit)
50 Equity in Earnings for Year (Credit) (Account 418.
51 (Less) Dividends Received (Debit)
53 Balance-End of Year (Total lines 49 thru 52)
Current Previous
QuarterN ear OuarterNear
Contra Primary Year to Date Year to Date
Account Affected Balance Balance
(b)(c)(d)
664 367,224
813,948
59,808
( 665,529,617)
162 393
662,613,084 ( 664 367 224)
FERC FORM NO. 1/3-0 (REV. 02-04)Page 119
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between .Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Line Description (See Instruction No.1 for Explanation of Codes)Current Year to Date Previous Year to Date
No.OuarterN ear OuarterNear
(a)(b)(c)
Net Cash Flow from Operating Activities:
Net Income (Line 78(c) on page 117)229 928 123 215,564 953
Noncash Charges (Credits) to Income:
Depreciation and Depletion 368,502,039 363,753,032
~_Qrtiza:f 756 548 229,637
Deferred Income Taxes (Net)888,432 60,575,388
Investment Tax Credit Adjustment (Net)920,120 920,120
Net (Increase) Decrease in Receivables 86,662 103 272 200
Net (Increase) Decrease in Inventory -8,600,017 16,973,244
Net (Increase) Decrease in Allowances Inventory
Net Increase (Decrease) in Payables and Accrued Expenses 192,647 958 036
Net (Increase) Decrease in Other Regulatory Assets 925,091 193,172
Net Increase (Decrease) in Other Regulatory Liabilities -58,370,244 -67 641 258
(Less) Allowance for Other Funds Used During Construction 163,409 12,943,772
(Less) Undistributed Earnings from Subsidiary Companies 820,142 418 704
556,414 133 601 263
Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)709,740,715 828,490,079
Cash Flows from Investment Activities:
Construction and Acquisition of Plant (including land):
Gross Additions to Utility Plant (less nuclear fuel)739,978,745 -630 149 975
Gross Additions to Nuclear Fuel
Gross Additions to Common Utility Plant
Gross Additions to Nonutility Plant
(Less) Allowance for Other Funds Used During Construction
Other (provide details in footnote):
Cash Outflows for Plant (Total of lines 26 thru 33)739,978,745 630,149,975
Acquisition of Other Noncurrent Assets (d)
Proceeds from Disposal of Noncurrent Assets (d)969 744 034,393
Investments in and Advances to Assoc. and Subsidiary Companies 568,178 13,091 ,527
Contributions and Advances from Assoc. and Subsidiary Companies
Disposition of Investments in (and Advances to)
Associated and Subsidiary Companies
Purchase of Investment Securities (a)
Proceeds from Sales of Investment Securities (a)
FERC FORM NO.1 (ED. 12-96)Page 120
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04
(2) n A Resubmission 04/25/2005
--c-STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Line Description (See Instruction No.1 for Explanation of Codes)Current Year to Date Previous Year to Date
No.QuarterlY ear QuarterlY ear
(a)(b)(c)
Loans Made or Purchased
Collections on Loans
Net (Increase) Decrease in Receivables
Net (Increase) Decrease in Inventory
Net (Increase) Decrease in Allowances Held for Speculation
Net Increase (Decrease) in Payables and Accrued Expenses
~.~~-
842,306 022 743
Net Cash Provided by (Used in) Investing Activities
Total of lines 34 thru 55)747,419,485 607,046 798
Cash Flows from Financing Activities:
Proceeds from Issuance of:
Long-Term Debt (b)394,982,159 396,980,000
Preferred Stock
Common Stock
Other (provide details in footnote):
Net Increase in Short-Term Debt (c)59,846,025 055,631
Other (provide details in footnote):
Cash Provided by Outside Sources (Total 61 thru 69)455,712 094 454 035,631
Payments for Retirement of:
Long-term Debt (b)283,975,000 168,231 107
Preferred Stock 500 000 500,000
Common Stock
Other (provide details in footnote):
Net Decrease in Short-Term Debt (c)
Dividends on Preferred Stock 083,790 792 540
Dividends on Common Stock 185,086,081 -120,807 145
Net Cash Provided by (Used in) Financing Activities
(Total of lines 70 thru 81)
Net Increase (Decrease) in Cash and Cash Equivalents
(Total of lines 22,57 and 83)611 547 10,519,120
Cash and Cash Equivalents at Beginning of Period 79,720,272 69,201 152
Cash and Cash Equivalents at End of period 19,108,725 79,720 272
FERC FORM NO.1 (ED. 12-96)Page 121
Name of Respondent
PacifiCorp
Date of Report
04/25/2005
Year/Period of Report
End of 2004/04
This Report Is:(1) An Original(2) D A Resubmission
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of
a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121 , such notes may be included herein.
7. For the 30 disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 30 disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REOUIRED INFORMATION.
FERC FORM NO.1 (ED. 12-96)Page 122
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Pacifi Co rp
(Electric Utility Only)
Notes to the Electric Utility Only Financial Statements
(Unaudited)
Note 1 - Basis of Presentation and Summary of Significant Accounting Policies
These financial statements are prepared in accordance with the requirements of the Federal Energy Regulatory Commission ("FERC"
as set forth in its applicable Urn form System of Accounts and published accounting releases, which is a comprehensive basis of
accounting other than generally accepted accounting principles. These notes include specific information requested by the FERC. See
PacifiCorp s Annual Report on Form 10-K as of, and for the year ended, March 31 , 2004 for financial statements and complete
footnotes prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"
The following are significant differences between FERC reporting standards and GAAP:
Investments in Subsidiaries
PacifiCorp accounts for its investments in majority-owned subsidiaries using the equity method rather than consolidating the
assets, liabilities, revenues and expenses of the subsidiaries as required by GAAP. GAAP requires that majority-owned
subsidiaries and variable-interest entities for which a company is the primary beneficiary be consolidated in accordance with
Statement of Financial Accounting Standards ("SFAS") No. 94, Consolidation of All Majority-Owned Subsidiaries and FASB
Interpretation No. 46, Consolidation of Variable-Interest Entities, an interpretation of Accounting Research Bulletin No. 51. In
general, the accounting for investments in majority-owned subsidiaries using the equity method rather than the consolidation
method in accordance with GAAP has no effect on net income or retained earnings.
Accumulated Removal Costs
The accumulated net removal costs for PacifiCorp' s regulated plant assets that do not meet the definition of an asset retirement
obligation under SF AS No. 143, Accounting for Asset Retirement Obligations are classified as a regulatory liability under GAAP
and as accumulated depreciation under FERc.
Accumulated Deferred Income Taxes
Accumulated deferred income taxes are classified as current and non-current for GAAP, by presenting net current assets and
liabilities separate from net non-current assets and liabilities on the balance sheet in accordance with SFAS No. 109, Accounting
for Income Taxes. All such amounts are classified as gross non-current assets and gross non-current liabilities for FERc.
Gains and Losses on Derivative Instruments
FERC requires that unrealized gains and losses on derivative instruments be classified gross on the income statement in
accordance with FERC Order 627, Accounting and Reporting of Financial Instruments, Comprehensive Income, Derivatives and
Hedging Activities. Unrealized gains on wholesale sales and purchased power are reported in Other Income and unrealized losses
on wholesale sales and purchased power are reported in Other Income and Deductions. For GAAP reporting purposes, unrealized
gains and losses on wholesale sales are reported in wholesale sales revenue and unrealized gains and losses on purchased power
are reported in purchased power expense.
Reclassifications
Certain reclassifications of balance sheet and income statement amounts have been made to assist in multi-jurisdictional
ratemaking process and conform to internal policies. These reclassifications had no effect on net income.
These financial statements have been prepared using accounting policies consistent with those applied at March 31 , 2004 in the
supplemental FERC filing, except in relation to new accounting standards.
FERC FORM NO.ED. 12-Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
These notes to the financial statements for the tweI ve months ended December 31, 2004 and 2003, are presented in accordance with
SEC interim reporting requirements based on FERC accounting requirements which represent abbreviated notes included for the
Company s interim periods. Full footnote disclosures are made in PacifiCorp s Supplement to the FERC Fonn 1, which represents the
Company s SEC reporting fiscal year ended March 31, 2005.
During the twelve months ended December 31, 2004, PacifiCorp changed the estimated average lives of certain computer software
systems to reflect operational plans. This change will reduce amortization expense by approximately $12.9 million annually on existing
computer software systems, with an annual impact to net income of approximately $8.0 million for the period.
Stock-Based Compensation
PacifiCorp has elected to account for its stock-based compensation arrangements under the intrinsic value recognition and
measurement principles prescribed by Accounting Principles Board ("APB") Opinion No. 25, Accounting for Stock Issued to
Employees APB No. 25"), whereby the options are granted with an exercise price that equals the market price of the underlying stock
on the date of grant and therefore no compensation expense is recorded. All options are for ScottishPower American Depository
Shares. Had PacifiCorp determined compensation cost based on the fair value recognition principles of Statement of Financial
Accounting Standards ("SFAS") No. 123, Accounting for Stock-Based Compensation SFAS No. 123"), PacifiCorp s net income
would have been changed to the following pro forma amounts:
(M illions of dollars)
Twelve Months
Ended
December 31,
2004
Twelve Months
Ended
December 31,
2003
Net income as rep orted
Add: stock-based compensation expense using the intrinsic
value method, net of tax of $.6 for 2004
Less: stock-based compensation expense using the fair value
method, net of tax of $( 1.5) for 2004 and $(.4) for 2003
229.215.
1.0
(2.4 )(0.
Pro forma net income 228.214.
See New Accounting Standards for discussion of Revised SF AS No. 123.
New Accounting Standards
FSP SFAS No. 106-
In May 2004, the Financial Accounting Standards Board ("FASB") released FASB Staff Position ("FSP") SFAS No. 106-
Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of2003
FSP SF AS No. 106-). FSP SF AS No. 106-2 provides guidance on the accounting for the effects of the Medicare Act for employers
that sponsor postretirement health care plans that offer prescription drug benefits and requires those employers to disclose the effect of
the federal subsidy afforded by the Medicare Act. For entities that elected deferral under FSP SF AS No. 106-Accounting and
Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of2003 FSP SFAS No.
106-), and for which the impact is significant, FSP SFAS No. 106-2 was effective for the first interim or annual period beginning
after June 15,2004. When FSP SFAS No. 106-2 became effective, it superceded FSP SFAS No. 106-1. PacifiCorp elected to adopt
FSP SF AS No. 106-2 early upon its release with retroactive application to PacifiCorp s Welfare Benefits Plan December 31, 2003
measurement date. Because that measurement date is used only to determine net periodic postretirement benefit cost for the period
beginning April 1, 2004, there was no impact on previously reported information. The effects of the Medicare Act decreased
PacifiCorp s accumulated postretirement benefit obligation by $42.6 million. This decrease is treated as an actuarial experience gain.
This actuarial experience gain reduces the unrecognized net loss resulting from differences in prior periods between actuarial
assumptions and actual experience. The actuarial experience gain will be amortized to expense through a decrease in the amortization
FERC FORM NO.ED. 12-Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 04/25/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
of the unrecognized net loss. The effects of the Medicare Act decreased net periodic postretirement benefit cost for the twelve months
ended December 31 , 2004, when compared to the expense calculated before the adoption ofFSP SFAS No. 106-2, as follows:
(Millions of dollars)
Twelve Months Ended
December 31
2004
Effect on:
In teres t co s t
Service Cost
Amortization of unrecognized loss
Net periodic pos tretirement benefit cos t
EITF No. 03-1 and FSP EITF No. 03-
In June 2004, the Emerging Issues Task Force ("EITF') issued EITF No. 03-1, The Meaning of Other- Than-Temporary Impairment
and Its Application to Certain Investments ("EITF No. 03-). Application guidance in EITF No. 03-1 should be used to determine
when an investment is considered impaired, whether that impairment is other than temporary, and the measurement of such
impairment. The guidance also includes accounting considerations subsequent to the recognition of an other-than-temporary
impairment and requires certain disclosures in annual financial statements about unrealized losses that have not been recognized as
other-than-temporary impairments.
In September 2004, the FASB issued FSP EITF No. 03-Effective Date of Paragraphs 10-20 of EITF No. 03-, The Meaning of
Other-Thall-Temporary Impairment and Its Application to Certain Investments FSP EITF No. 03-). FSP EITF No. 03-
delayed the previously required effective date of July 1, 2004 for PacifiCorp regarding the measurement and recognition guidance
contained in the applicable paragraphs. The delay of the effective date is likely to be superceded with the final issuance of an FSP on
other-than-temporary impairment of investments. The adoption of the measurement and recognition guidance of EITF No. 03-1, if
implemented in its present form, is not anticipated to have a material impact on PacifiCorp s financial position or results of operations.
SFAS No. 151
In November 2004, the FASB issued SF AS No. 151, Inventory Costs SFAS No. 151"), which amends Accounting Research Bulletin
No. 43, Chapter 4 Inventory Pricing. SFAS No. 151 requires that abnormal amounts of idle facility expense, freight, handling costs
and wasted material (spoilage) be included as current-period charges, eliminating the option for capitalization. This statement is
effective for inventory costs that PacifiCorp incurs after April 1 , 2006. PacifiCorp does not typically incur abnormal costs related to
inventory balances; therefore, the adoption of this statement is not anticipated to have a material impact on PacifiCorp ' s financial
position or results of operations.
SFAS No. 153
In December 2004, the FASB issued SFAS No. 153, Exchanges of Non-monetary Assets SFAS No. 153"), which amends APB
Opinion No. 29, Accounting for Non-monetary Transactions APB No. 29"). SFAS No. 153 eliminates the exception from fair value
measurement for non-monetary exchanges of similar productive assets in APB No. 29 and replaces it with an exception for exchanges
that do not have commercial substance. This statement specifies that a non-monetary exchange has commercial substance if the future
cash flows of the entity are expected to change significantly as a result of the exchange. The provisions in this statement will apply to
PacifiCorp for any exchanges of non-monetary assets that occur after April 1, 2006. The adoption of this statement is not expected to
have a material impact on PacifiCorp' s financial position or results of operations.
SFAS No. 123R -
In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment SFAS No. 123R"), a revision of the originally issued
SFAS No. 123. SFAS No. 123R establishes standards for the accounting for transactions in which an entity exchanges its equity
instruments for goods or services. This statement requires that the cost resulting from all share-based payment transactions be
recognized in the financial statements using the fair value method. The intrinsic value method of accounting established by APB No.
25 will no longer be allowed.
FERC FORM NO.ED. 12-88 Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
In April 2005, the effective date of this statement was deferred until the beginning of the fiscal year that begins after June 15,2005;
however, early adoption is encouraged. A modified prospective application is required for new awards and to awards modified,
repurchased or cancelled after the required effective date. The PacifiCorp Stock Incentive Plan (the "PSIP") expired November 29,
2001; therefore, no new awards are expected to be issued, modified, repurchased or cancelled as of the effective date. As ofthe
effective date, all requisite service under the PSIP will have been previously rendered; therefore, no compensation expense is expected
to result from the adoption of this statement in relation to the PSIP.
Certain PacifiCorp employees receive awards under various ScottishPower share-based payment plans. Application to these awards of
the fair value method required by SF AS No. 123R, as compared to the application of the intrinsic value method allowed under APB
No. 25 is not expected to result in a material change to recorded compensation expense upon adoption of SPAS No. 123R.
FSP SFAS No. 109-
In December 2004, the F ASB issued FSP SF AS No.1 09-1, Application ofF ASB Statement No.1 09, Accounting for Income Taxes, to
the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of2004. This tax deduction will be
treated as a "special deduction" as described in SPAS No. 109, Accounting for Income Taxes. As such, the special deduction has no
effect on deferred tax assets and liabilities existing at the enactment date. Rather, the impact of this deduction will be reported in the
period in which the deduction could be claimed on a separate return basis in accordance with PacifiCorp s accounting policy. This
statement became effective upon issuance. The impact of the deduction to PacifiCorp will depend on the application of forthcoming
guidance from the Internal Revenue Service to PacifiCorp s future qualifying electric generation activities and cannot be estimated at
this time.
FIN 47
In March 2005, the F ASB issued F ASB Interpretation No.4 7, Accounting for Conditional Asset Retirement Obligations
Interpretation of FASB Statement No. 143 FIN 47"). This Interpretation clarifies that the term "conditional asset retirement
obligation" as used in SPAS No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or
method of settlement are conditional on a future event that mayor may not be within the control of the entity. The obligation to
perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement.
Thus, the timing and/or method of settlement may be conditional on a future event. This Interpretation clarifies that an entity is
required to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability's fair value
can be reasonably estimated. FIN 47 is effective for the end of fiscal years ending after December 31, 2005. PacifiCorp is currently
evaluating the impact of adopting FIN 47 on its consolidated financial position and results of operations.
Note 2 - Accounting for the Effects of Regulation
PacifiCorp records regulatory assets and liabilities based on management's assessment that it is probable that a cost will be recovered
(asset) or that an obligation has been incurred (liability) in accordance with the provisions of SPAS No. 71, Accounting for the Effects
of Certain Types of Regulation. The final outcome, or additional regulatory actions, could change management's assessment in future
periods.
Regulatory assets include the following:
FERC FORM NO.ED. 12-88 Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(Millions of dollars)December 31,2004 December 31,2003
Deferred income taxes
Minimum pension liability offset
Deferred net power cos ts (a)
Demand-side resource costs
Transition Plan costs - retirement and severance
Various other cos ts
Subtotal
Deriv ativ e Con tracts (b)
Total
536.
233.
78.
42.3
44.
111.9
047.
526.
574.
501.0
226.
26.
28.
28.4
103.
913.
277.
191.1
(a)Represents deferred net power costs in Oregon at December 31, 2004 and in Utah, Oregon and Idaho at
December 31, 2003 that PacifiCorp is recovering through rates.
Represents the fair market value of the current and non-current derivative contracts that are specifically
recoverable through rates.
(b)
Regulatory liabilities include the following:
(Millions of dollars)December 31 2004 December 31,2003
Deferred income taxes
Regulatory credits
Various other costs
Total
45.4
60.
22.
128.
37.
93.
12.
142.
PacifiCorp evaluates the recovery of all regulatory assets periodically and as events occur. The evaluation includes the probability of
recovery, as well as changes in the regulatory environment. Regulatory and/or legislative actions in Utah, Oregon, Wyoming,
Washington, Idaho and California may require PacifiCorp to record regulatory asset write-offs and charges for impairment of
long-lived assets in future periods.
Note 3 - Derivative Instruments
PacifiCorp s derivative instruments are recorded on the Balance Sheets as assets or liabilities measured at estimated fair value, unless
they qualify for certain exemptions permitted under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities,
amended. Changes in fair value ofPacifiCorp s recorded derivative contracts are recognized immediately in the income statement,
except for contracts that have received regulatory approval for recovery in retail rates. Such changes in fair value are deferred as
regulatory assets or liabilities until realized. Unrealized and realized gains and losses from all derivative contracts held for trading
purposes, including those where physical delivery is required, are recorded gross. Realized gains and losses from derivative contracts
not held for trading purposes are recorded gross unless the contracts do not result in physical delivery.
The following table summarizes the changes in fair value of PacifiCorp s derivative contracts executed for balancing system resources
and load obligations (non-trading), and for taking advantage of arbitrage opportunities (trading) for the twelve months ended
December 31, 2004.
FERC FORM NO.ED. 12-88 Page 123.5 .
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(Millions of dollars)
Net Regulatory
Asset (Liabilit Net asset
Tradin Non-Tradin (Liabilit ) (b:
Fair value of contracts outstanding at December 31, 2003
Contracts realized or otherwise settled during the period
Other changes in fair values (a)
(527.526.
(1.2)(0.(0.
256.(248.3)
(271.5 277.Fair value of contracts outstanding at December 31,2004
(a)Effective September 30, 2004, PacifiCorp changed to a U.S. London Interbank Offered Rate (LffiOR) rate
from the U.S. Treasury rate for discounting the portfolio. This change had the effect of increasing the fair
value of non-trading contracts by $25.5 million, offset by a decrease in regulatory net assets by the same
amount. Other changes in fair values include the effects of this change, along with the effects of changes in
market prices, inflation rates and interest rates, including those based on models, on new and existing
contracts for the twelve months ended December 31, 2004.
Contracts that have received commission approval for regulatory recovery are included as a Regulatory Net
Asset (Liability).
(b)
Weather derivatives - PacifiCorp estimates and records an asset or liability corresponding to the total expected future cash flow from
its non-exchange traded weather derivatives in accordance with EITF No. 99-2, Accounting for Weather Derivatives. The net liability
recorded for these contracts was $1.7 million at December 31, 2004 and $3.4 million at December 31 , 2003. PacifiCorp recognized a
gain of $2.9 million for the twelve months ended December 31, 2004 and a gain of $5.2 million for the twelve months ended
December 31, 2003.
Note 4 - Related-Party Transactions
There are no loans or advances between PacifiCorp and ScottishPower or between PacifiCorp and PacifiCorp Holdings, Inc. ("Pill"
PacifiCorp s direct parent. Loans from PacifiCorp to ScottishPower or PHI are prohibited under the Public Utility Holding Company
Act of 1935. Loans from ScottishPower or Pill to PacifiCorp generally require state regulatory and SEC approval. There are
intercompany ~oan agreements that allow funds to be lent from PacifiCorp Group Holdings Company ("PGHC") to PacifiCorp, but
loans from PaclfiCorp to PGHC are prohibited. There are intercompany loan agreements that allow funds to be lent between
PacifiCorp and ,Pacific Minerals, Inc., a wholly owned subsidiary of PacifiCorp. PacifiCorp does not maintain a centralized cash or
money pool. Therefore, funds of each company are not commingled with funds of any other company. Other affiliate transactions that
PacifiCorp enters into are subject to certain appr9val and reporting requirements of the regulatory authorities.
Commencing on April 1, 2004, PacifiCorp and Scottish Power UK pIc ("SPUK"), an indirect subsidiary of ScottishPower,
implemented a cross-charge policy governing the allocation of costs incurred by PacifiCorp and SPUK, on behalf of each other. These
cross-charges commenced during the nine months ended December 31, 2004 and were recorded in operations and maintenance
expense. These cross-charges amounted to $12.4 million for the nine months ended December 31, 2004.
In May 2002, PacifiCorp entered into a IS-year operating lease for an electric generation facility with West Valley Leasing Company,
LLC ("West V alley ). West Valley is a subsidiary of PPM Energy, Inc. ("PPM"), which is a direct subsidiary of Pill and an indirect
subsidiary of ScottishPower. The facility consists of five generation units, each rated at 40 megawatts ("MW"), and is located in Utah.
The lease terms granted PacifiCorp two independent early termination options that provide PacifiCorp the right to terminate the lease
and, at PacifiCorp s further option, to purchase the facility for predetermined amounts. On May 28, 2004, PacifiCorp exercised its first
option to terminate the West Valley lease. PacifiCorp subsequently exercised its right to rescind the termination on September 28,
2004 after determining, through a public process, that the resource could not be replaced on a more economic basis and without
increasing risks to system reliability. PacifiCorp has a second option to terminate the West Valley lease if written notice is provided to
West Valley on or before December 1,2006. PacifiCorp is committed to future minimum lease payments of $15.0 million annually for
years ending March 31, 2005 through 2008 and $2.5 million for the year ending March 31, 2009.
FERC FORM NO.ED. 12-Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The following tables detail PaCifiCorp s transactions and balances with unconsolidated related parties:
FERC FORM NO.ED. 12-88 Page 123.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
...
Ine Account B~lance AcCitlons
No.Beginning of Year
(a)(b)(c)
(347) Asset Retirement Costs for Other Production 674 204 181 672
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)279,183,871 428 452
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)129,606.624 144 929,531
3. TRANSMISSION PLANT
(350) Land and Land Rights 462 622 364,637
(352) Structures and Improvements 46,825,266 893,951
(353) Station Equipment 821 170 629 736,504
(354) Towers and Fixtures 357 736,579 046 748
(355) Poles and Fixtures 465 234 177 557 723
(356) Overhead Conductors and Devices 599,619 234 052 842
(357) Underground Conduit 364 264 939
(358) Underground Conductors and Devices 914 194 88,372
(359) Roads and Trails 11 ,337 970 32,203
(359.1) Asset Retirement Costs for Transmission Plant
TOTAL Transmission Plant (Enter Total of lines 48 thru 57)396,664 935 101 775 919
4. DISTRIBUTION PLANT
(360) Land and Land Rights 29,594,119 616 802
(361) Structures and Improvements 571,745 145 179
(362) Station Equipment 578 938,583 638 613
(363) Storage Battery Equipment
(364) Poles, Towers, and Fixtures 716,902,585 34,668,268
(365) Overhead Conductors and Devices 544 811 628 714 533
(366) Underground Conduit 227 880,769 519 162
(367) Underground Conductors and Devices 519,182,784 756 730
(368) Line Transformers 814 960,079 177 091
(369) Services 357,964,067 521,573
(370) Meters 180 674 402 028 218
(371) Installations on Customer Premises 976 258 104 779
(372) Leased Property on Customer Premises 49,658
(373) Street Lighting and Signal Systems 753,171 702,373
(374) Asset Retirement Costs for Distribution Plant
TOTAL Distribution Plant (Enter Total of lines 60 thru 74)066 259,848 219,593,321
5. GENERAL PLANT
(389) Land and Land Rights 14,934 824
(390) Structures and Improvements 208,467 179 198 468
(391) Office Furniture and Equipment 113,651,782 26,511,869
(392) Transportation Equipment 220,383 377,360
(393) Stores Equipment 10,727 361 487 960
(394) Tools, Shop and Garage Equipment 995 986 650,207
(395) Laboratory Equipment 33,712,479 338,750
(396) Power Operated Equipment 104,742,588 13,608,550
(397) Communication Equipment 216 249,811 153 852
(398) Miscellaneous Equipment 509 377 266 492
SUBTOTAL (Enter Total of lines 77 thru 86)833,211 770 71,593,508
(399) Other Tangible Property
(399.1) Asset Retirement Costs for General Plant
TOTAL General Plant (Enter Total of lines 87 88 and 89)089,896,298 308,812
TOTAL (Accounts 101 and 106)13,214 419,723 679,087 159
(102) Electric Plant Purchased (See Instr. 8)
(Less) (102) Electric Plant Sold (See Instr. 8)260 525
(103) Experimental Plant Unclassified
TOTAL Electric Plant in Service (Enter Total of lines 91 thru 94)13,208,159,198 679,087 159
FERC FORM NO.1 (REV. 12-03)Page 206
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(Millions of dollars)December 31,December 31,
2004 2003
Amounts due from affiliated entities:
ScottishPower (a)0.4
PHI subs idiaries (b)1.6
PacifiCorp subsidiaries (c)
5.4
Prepayments to affiliated entities:
PHI subsidiaries (d)41.9 5.1
Amounts due to affiliated entities:
ScottishPower (e)8.3
PHI subsidiaries (t)11.2
PacifiCorp subs idiaries (g)28.29.
48.4 32.4
Deposits received from affiliated entities:
PHI subsidiaries (h)1.1 1.1
Twelve Months Twelve Months
Ended Ended
December 31 December 31,
(Millions of dollars) 2004 2003
Rev en ues from affiliated en tities:
PHI and subsidiaries (h)
Expenses incurred from affiliated entities:
ScottishPower (e)17.
PHI and subsidiaries (d)17.17.
PacifiCorp subsidiaries (i)76.75.
111.6 99.
Expenses recharged to affiliated entities:
ScottishPower (a)
PHI and subsidiaries (b)7.2
PacifiCorp subsidiaries (c)15.14.
26.22.
Interest expense to affiliated entities:
PHI and subsidiaries 0)
PacifiCorp subsidiaries (k)
0.2
0.4
19.
19.
FERC FORM NO.ED. 12-Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmisslon 04/25/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
(a)PacifiCorp recharges to ScottishPower payroll costs and related benefits of employees working on
international assignments in the United Kingdom.
Amounts shown pertain to activities of PacifiCorp with PHI and its subsidiaries. Expenses recharged reflect
costs for support service to PHI and its subsidiaries.
Amounts shown reflect costs recharged for support services to PacifiCorp s subsidiaries.
Includes prepaid income taxes paid to PHI of $5.1 million at December 31, 2003 and $41.9 million at
December 31 , 2004. PHI is the tax-paying entity for PacifiCorp.
These expenses and liabilities primarily represent allocated costs under the affiliated interest cross-charge
policy with SPUK, effective April 1, 2004 and payroll costs and related benefits of SPUK employees
working for PacifiCorp in the United States.
Includes state income taxes payable to PHI of $11.1 million and $0.1 million in interest payable to PHI
subsidiaries at December 31, 2004.
Amounts due to affiliates of $28.9 million for December 31, 2004 represents, $20.5 million in short-term
demand loans and $8.4 million in coal purchases payable to PMI. Amounts due to affiliates of $29.7 million
for December 31, 2003 represents, $19.6 million in short-term demand loans and $10.1 million in coal
purchases payable to PMI.
These revenues and the associated deposit relate to wheeling services billed to PPM, a subsidiary of PHI.
Represents coal purchase and extraction expenses of $75.1 million for the twelve months ended December
31,2004 and $74.0 million for the twelve months ended December 31, 2003 from the Bridger and Trapper
coal mines, as well as the cost of environmental services provided by PacifiCorp Environmental
Remediation Company of $1.6 million for the twelve months ended December 31, 2004 and $1.3 million for
the twelve months ending December 31, 2003.
Includes interest on deposits from PPM and PGHC umbrella loan.
Includes interest on intercompany debt that was repaid during August 2003 in connection with the
redemption of subsidiary trust preferred securities and interest on short-term demand loans made to
PacifiCorp by PMI.
(b)
(c)
(d)
(e)
(t)
(g)
(h)
(i)
(j)
(k)
Note 5 - Financing Arrangements
At December 31, 2004, PacifiCorp had an $800.0 million committed bank revolving credit agreement, which was fully available, and
which had no borrowings outstanding. This facility, which has a three-year term, became effective May 28 2004 and was used to
replace an expiring $500.0 million facility, as well as a $300.0 million facility that was terminated by PacifiCorp prior to its maturity.
The interest on advances under this new facility is based on the London Interbank Offered Rate (LffiOR) plus a margin that varies
based on PacifiCorp' s credit rating.
In September 2004, PacifiCorp entered into a new $296.9 million letter of credit facility with a maturity date of September 14, 2007.
This facility provides credit enhancement and liquidity support for seven series of variable rate pollution control revenue bond
obligations. In connection with the commencement of this new facility, corresponding amounts of previously existing letters of credit
were cancelled.
PacifiCorp s credit agreements contain customary covenants and default provisions, including covenants not to exceed a specified
debt-to-capitalization ratio. PacifiCorp monitors these covenants on a regular basis to ensure that events of default will not occur. As of
December 31, 2004, PacifiCorp was in compliance with the covenants of its credit agreements.
Note 6 - Long-Term Debt
On August 24 2004, PacifiCorp issued $200.0 million of its 4.95% Series of First Mortgage Bonds due August 15,2014 and $200.
million of its 5.90% Series of First Mortgage Bonds due August 15 2034. PacifiCorp used the proceeds for general corporate
purposes, including the reduction of short-term debt. These bonds contain covenants consistent with PacifiCorp s other series of First
Mortgage Bonds.
FERC FORM NO.ED. 12-88 Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmisslon 04/25/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
During December 2004, PacifiCorp redeemed, prior to maturity, all of the 8.625% First Mortgage Bonds due in December 2024,
which totaled $20.0 million. Upon redemption, $1.3 million of deferred charges were reclassified to Unamortized Loss on Reacquired
Debt. This retirement was initially funded through short-term debt with the expectation that it will be funded through long-term
financing in the next 12 months, subject to regulatory authorization.
Note 7 - Commitments and Contingencies
PacifiCorp follows SFAS No.5, Accounting for Contingencies, to determine accounting and disclosure requirements for
contingencies. PacifiCorp operates in a highly regulated environment. Governmental bodies such as the Federal Energy Regulatory
Commission (the "FERC"), the SEC, the Internal Revenue Service, the Department of Labor, the United States Environmental
Protection Agency (the "EP A") and others have authority over various aspects of PacifiCorp s business operations and public
reporting. Reserves are established when required, in management's judgment, and disclosures regarding litigation, assessments and
creditworthiness of customers or counterparties, among others, are made when appropriate. The evaluation of these contingencies is
performed by various specialists inside and outside of PacifiCorp.
Liti ation
In May 2004, PacifiCorp was served with a complaint filed in the United States District Court for the District of Oregon by the
Klamath Tribes of Oregon, individual Klamath Tribal members and the Klamath Claims Committee. The claim generally alleges that
PacifiCorp and its predecessors affected the Klamath Tribes' federal treaty rights to fish for salmon in the headwaters of the Klamath
River in southern Oregon by building dams that blocked the passage of salmon upstream to the headwaters beginning in 1911. In July
2004, PacifiCorp filed its answer to the complaint. In September 2004, the case was transferred to the Medford Division of the District
of Oregon. Also in September 2004, the Klamath Tribes filed their first amended complaint adding claims of damage to their treaty
rights to fish for sucker and steelhead in the headwaters of the Klamath River. The claim seeks in excess of $1.0 billion in
compensatory and punitive damages. In October 2004, PacifiCorp filed its answer to the first amended complaint generally denying
liability and asserting affmnative defenses for the matters alleged by the Klamath Tribes. A scheduling conference was held in October
2004, which established a procedural schedule for the case. In February 2005, PacifiCorp filed a motion for summary judgment
seeking dismissal of the Klamath Tribe s case as untimely under the applicable statute of limitations. Oral argument on the motion for
summary judgment was held on April 12, 2005. On April 14, 2005, the magistrate judge issued an opinion recommending that
PacifiCorp s motion for summary judgment be granted and the case be dismissed as untimely. Parties have until May 3, 2005 to file
objections to the recommendation. The final order will be subject to appeal.
From tirne to time, PacifiCorp is also a party to various other legal claims, actions and complaints, certain of which involve material
amounts. Although PacifiCorp is unable to predict with certainty whether it will ultimately be successful in these legal proceedings or,
if not, what the impact might be, management currently believes that disposition of these matters will not have a material adverse effect
on PacifiCorp s financial position or results of operations.
Environmental Issues
PacifiCorp is subject to numerous environmental laws, including the federal Clean Air Act and various state air quality laws; the
Endangered Species Act, particularly as it relates to certain endangered species of fish; the Comprehensive Environmental Response
Compensation and Liability Act, and similar state laws relating to environmental cleanups; the Resource Conservation and Recovery
Act and similar state laws relating to the storage and handling of hazardous materials; and the Clean Water Act, and similar state laws
relating to water quality. These laws could potentially impact future operations. Contingencies identified at December 31, 2004,
principally consist of air quality matters. Pending or proposed air regulations will require PacifiCorp to reduce its electricity plant
emissions of sulfur dioxide, nitrogen oxides and other pollutants below current levels. These reductions will be required to address
regional haze programs, mercury emissions regulations and possible re-interpretations and changes to the federal Clean Air Act. Also,
similar to many other coal burning utilities, PacifiCorp has received information requests from the EPA related to PacifiCorp
compliance with the New Source Review provisions of the Clean Air Act, which has resulted in some discussions with the EP A and
state regulatory authorities. PacifiCorp in the future may incur significant costs to comply with various tighter air emissions
requirements. These potential costs are expected to consist primarily of capital expenditures. PacifiCorp expects these costs would be
included in rates and, as such, would not have a material adverse impact on PacifiCorp s consolidated results of operations.
FERC FORM NO.ED. 12-88 Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
PacifiCorp completed a study during the three months ended September 30, 2004 on sites for which it may be obligated to perform
environmental remediation. As a result, during the three months ended September 30, 2004 PacifiCorp adjusted its reserve by $1.
million to reflect its most likely estimate for probable liabilities. In the three months ended December 31, 2004, PacifiCorp recognized
an additional $3.4 million for new probable environmental liabilities. Remediation costs that are fixed and determinable have been
discounted to their present value. The liability was $15.5 million at December 31, 2004 and was $12.9 million at December 31, 2003.
The undiscounted liability totaled $15.7 million as of December 31, 2004 and PacifiCorp used a credit-adjusted, risk-free discount rate
to calculate the present value of the obligation. Should current circumstances change, it is possible that PacifiCorp could incur an
additional undiscounted obligation of up to approximately $24.1 million relating to existing sites.
droelectric Relicensin
PacifiCorp s hydroelectric portfolio consists of 54 plants with a plant net capability of 1163.5 MW. Ninety-seven percent of the
installed capacity is regulated by the FERC through 18 individual licenses. Several of PacifiCorp s hydroelectric projects are in some
stage of relicensing under the Federal Power Act. Hydroelectric relicensing and the related environmental compliance requirements are
subject to uncertainties. PacifiCorp expects that future costs relating to these matters may be significant and consist primarily of
additional relicensing costs, operations and maintenance expense, and capital expenditures. Electricity generation reductions may result
from the additional environmental requirements. PacifiCorphas accumulated approximately $57.3 million in costs as of December 31,
2004, for ongoing hydroelectric relicensing that are reflected in assets on the Balance Sheet.
In May 2004, PacifiCorp accepted the new license for the Bear River hydroelectric project. PacifiCorp is committed, over the life of
the license, to fund approximately $26.5 million for environmental mitigation and enhancement projects. A $12.2 million liability,
representing the present value of these obligations, was recorded in May 2004.
The new FERC license for the North Umpqua hydroelectric project, is effective, but not final. When the license for this project
becomes final, PacifiCorp will be committed, over the life of the license, to fund approximately $48.9 million for environmental
mitigation and enhancement projects. A $13.0 million liability, representing the present value of certain obligations specified in the
license, was recorded in June 2004. Additional liabilities will be recognized when the license becomes final.
In February 2004, PacifiCorp filed with the FERC a final application for a new license to operate the 161.4 MW Klamath hydroelectric
project in southern Oregon and northern California. The FERC is scheduled to complete its required analysis by April 2006. In the
meantime, PacifiCorp continues to work cooperatively with a broad range of stakeholders to identify and resolve any outstanding
issues in an attempt to reach a settlement. In October 2004, PacifiCorp convened a mediated settlement negotiation group consisting of
itself, state and federal agencies, Native American tribes, and other stakeholders, in an effort to reach a comprehensive agreement on
project relicensing.
On November 30, 2004, PacifiCorp executed a comprehensive settlement agreement with 25 other parties including state and federal
agencies, Native American tribes, conservation groups, and local government and citizen groups to resolve, among the parties, issues
related to the pending applications for new licenses for PacifiCorp s 136.0 MW Merwin, 240.0 MW Swift No.1 and 134.0 MW Yale
hydroelectric projects on the Lewis River in southwest Washington. As part of this settlement agreement, PacifiCorp has agreed to
implement certain protection, mitigation and enhancement measures prior to and during a proposed 50-year license period. However,
these commitments are contingent on ultimately receiving a license from the FERC that is consistent with the settlement agreement and
other required permits. The FERC is scheduled to complete its process and required analysis in order to be ready for a decision in
March 2006.
Swift Power Canal
On April 21, 2002, a failure occurred to the Swift No.2 power canal located on the Lewis River in the state of Washington and owned
by the Cowlitz County Public Utility District. The failure impacted, but did not damage, the PacifiCorp-owned and -operated 240 MW
Swift No.1 hydroelectric facility, which is upstream of the Swift No.2 power canal. In June 2004, PacifiCorp and Cowlitz County
Public Utility District amended the existing power purchase agreement addressing, among other things, the general nature of the canal
rebuild configuration and providing the mechanism for settling all claims between the parties related to the canal failure. Cowlitz
County Public Utility District has initiated the reconstruction of the Swift No.2 project facility with contracts currently in place for
rehabilitation of the turbine generators, switchyard and reconstruction of the Swift No.2 power canal. Based on the current schedule,
the first Swift No.2 turbine generator unit is expected to be on line in the first quarter of calendar year 2006 and the second unit is
FERC FORM NO.ED. 12-88 Page 123.
: Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
expected to follow shortly thereafter.
Enron Cor . Reserves
In December 2001, Enron Corp. declared bankruptcy and defaulted on certain wholesale contracts. PacifiCorp has fully reserved for its
$8.0 million Enron Corp. receivable. On January 28, 2005, PacifiCorp entered an agreement to sell the bankruptcy claim to a third
party. Closing of the sale occurred in the first quarter of calendar year 2005.
FERC Issues
Qillfornia Re nd Case - PacifiCorp is a party to a FERC proceeding that is investigating potential refunds for energy transactions in
the California Independent System Operator and the California Power Exchange markets during past periods of high energy prices.
PacifiCorp has a reserve of $17.7 million for these potential refunds. PacifiCorp s ultimate exposure to refunds is dependent upon any
final order issued by the FERC in this proceeding. In addition, in summer 2000, California market conditions resulted in defaults of
amounts due to PacifiCorp from certain counterparties resulting from transactions with the California Independent System Operator
and California Power Exchange. PacifiCorp has reserved $5.0 million for these receivables.
Northwest nd Case - In June 2003, the FERC terminated its proceeding relating to the possibility of requiring refunds for
wholesale spot-market bilateral sales in the Pacific Northwest between December 2000 and June 2001. The FERC concluded that
ordering refunds would not be an appropriate resolution of the matter. In November 2003, the FERC issued its final order denying
rehearing. Several market participants have filed petitions in the court of appeals for review of the FERC's final order. Court briefs
from interested parties are due to be filed between January 14,2005 and April 15, 2005. A decision from the court of appeals is not
expected to have a significant impact on PacifiCorp s financial position or results of operations.
Federal Power Act Section 206 Case - In June 2003, the FERC issued a final order denying PacifiCorp s request for recovery of
excessive prices charged under certain wholesale electricity purchases scheduled for delivery during summer 2002 and dismissing
PacifiCorp s complaints, under Section 206 of the Federal Power Act, against five wholesale electricity suppliers. In July 2003,
PacifiCorp filed its request for rehearing of the FERC's order, which request was granted in August 2003. The FERC issued its final
order denying rehearing in November 2003. In November 2003, PacifiCorp filed a petition in the Ninth Circuit Court of Appeals for
review of the FERC's final order denying recovery. Court briefs from interested parties are due to be filed by March 1, 2005.
FERC Show-Cause Orders - In May 2002, PacifiCorp, together with other California electricity market participants, responded to data
requests from the FERC regarding trading practices connected with the electricity crisis during 2000 and 2001. PacifiCorp confirmed
that it did not engage in any trading practices intended to manipulate the market as described in the FERC's data requests issued in
May 2002. In June 2003, the FERC ordered 60 companies (including PacifiCorp) to show cause why their behavior during the
California energy crisis did not constitute manipulation of the wholesale electricity market, as defined in the California Independent
System Operator and the California Power Exchange tariffs. In setting the cases for hearing, the FERC directed the administrative law
judge to hear evidence and render findings and conclusions quantifying the extent of any unjust enrichment that resulted and to
recommend monetary or other appropriate remedies. In August 2003, PacifiCorp and the FERC staff reached a resolution on the
show-cause order. Under the terms of the settlement agreement, PacifiCorp denied liability and agreed to pay a nominal amount of
$67,745, in exchange for complete and total resolution of the issues raised in the FERC's show-cause order relating to PacifiCorp. In
March 2004, the FERC issued its final order approving the settlement and terminating the docket. In April 2004, certain market
participants filed a request for rehearing of the FERC's final order. A decision from the FERC on the rehearing requests is pending.
The Bonneville Power Administration Residential Exchan e Pro ram
The Northwest Power Act, through the Residential Exchange Program, provides access to the benefits of low-cost federal
hydroelectricity to the residential and small-farm customers of the region s investor-owned utilities. The Bonneville Power
Administration (the "BPA") administers the Residential Exchange Program in accordance with federal law. Pursuant to a set of
agreements between the BPA and PacifiCorp, PacifiCorp receives benefits from the BPA and passes such benefits through to its
Oregon, Washington and Idaho residential and small-farm customers in the form of electricity bill credits in the annual amount of
approximately $119.0 million for BPA's fiscal years 2002 through 2006. (BPA's fiscal year is October 1 through September 30.) On
May 28, 2004, PacifiCorp, the BP A and other parties executed an additional agreement that provides for a guaranteed range of benefits
to customers for BP A's fiscal years 2007 through 2011. This additional agreement provides a varying level of benefits each year based
on a formula that includes the level ofBPA's rates and the wholesale market price of power. The agreement also limits the level of
FERC FORM NO.ED. 12-88 Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
benefits in any year with a defined cap and floor.
Several publicly owned utilities, cooperatives and the BP A direct-service industry customers have filed lawsuits with the Ninth Circuit
Court of Appeals seeking review of certain aspects of the overall BP A Residential Exchange Program, as well as challenging the level
of benefits previously paid to investor-owned utility customers. This litigation could possibly affect the amount of benefits paid by the
BPA to PacifiCorp and, accordingly, the amount passed on to PacifiCorp s customers. However, since these benefits are passed
through to PacifiCorp s customers through adjustments to customer rates, which must be approved by state utility commissions, the
outcome of this litigation is not expected to have a significant effect on PacifiCorp s financial position or results of operations.
Note 8 - Retirement Benefit Plans
The components of net periodic benefit cost for the twelve months ended December 31 2004 and 2003 are as follows:
Retirement Plans
Twelve Months Twelve MonthsEnded Ended
December 31, December 312~ 2003
(Millions of dollars)
Serv ice Co s t 30.24.
Interes t Cos t 73.74.
Expected Return on Plan Assets (78.4)(83.
Amortization of Unrecognized Net Obligation 8.4 8.4
Amortization of Unrecognized Prior Service Cost 1.4 1.7
Amortization of Unrecognized Loss 6.4 (1.0)
Net Periodic Benefit Cos t 41.9 24.
(Millions of dollars)
Other Pos tretirement Benefits (a)
Twelve Months Twelve MonthsEnded Ended
December 31, December 312~ 2003
Service Cos t 7.4
In teres t Co s t 31.9 34.
Expected Return on Plan Assets (26.(27.
Amortization of Unrecognized Net Obligation 12.12.
Amortization of Unrecognized Prior Service Cost
Amortization of Unrecognized Loss 0.4
Net Periodic Benefit Cos t 26.27.
(a) Results for the twelve months ended December 31, 2004 reflect the impact of the new Medicare provisions described in Note
Note 9 - Income Taxes
PacifiCorp uses an estimated annual effective tax rate for computing the provision for income taxes on an interim basis.
PacifiCorp accrued federal and state income tax expense of $122.8 million for the twelve months ended December 31, 2004, and
FERC FORM NO.ED. 12-88 Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
$163.2 million for the twelve months ended December 31, 2003.
The total accrued federal and state income tax expense are as follows:
e Line Descri tion
Twelve Months
Ended
December 31
2004
Twelve Months
Ended
December 31,
2003
(Millions of dollars)
114
114
114
114
114
117
117
117
117
117
117
15 Income Taxes Federal 409.
16 Income Taxes Other 409.
17 Provision for Deferred Income Taxes 410.
18 (Less) Provision for Deferred Income Taxes 411.1
19 Investment Tax Credit 411.4
53 Income Taxes Federal 409.
54 Income Taxes Other 409.2
55 Provis ion for Deferred Income Taxes 410.
56 (Less) Provision for Deferred Income Taxes 411.2
57 Investment Tax Credit 411.5
58 (Less) Investment Tax Credits 420
45.113.3
(12.13.
715.228.
625.170.
(5.(5.
1.1 (16.
1.7
122.163.
PacifiCorp has established, and periodically reviews, an estimated contingent tax reserve on its Balance Sheets to provide for the
possibility of adverse outcomes in tax proceedings. During the twelve months ended December 31, 2004, PacifiCorp favorably settled
outstanding income tax issues with the State of Oregon related to PacifiCorp' s 1991 through 1998 Oregon income tax returns. The
settlement resulted in a release of previously accrued tax liability of $8.5 million. PacifiCorp also settled certain tax issues with the
Internal Revenue Service related to PacifiCorp s 1999 and 2000 federal income tax returns and, as a result, released $14.0 million of
previously provided tax contingency reserves. This release was partially offset by an increase to the tax contingency reserve of $6.4
million primarily to accrue interest on remaining tax contingencies provided for in prior periods. The resulting change in the tax
contingency reserve during the twei ve months ended December 31, 2004, was a net reduction of $16.1 million.
Note 10 - Comprehensive Income
The components of comprehensive income are as follows:
(Millions of dollars)
Twelve Months
Ended
December 31
2004
Twelve Months
Ended
December 31,
2003
Net income
Other comprehensive income (loss):
Minimum pension liability,
net oftaxes of $3.8 for 2004 and $1.1 for 2003
Unrealized gain on av ailable-for-s ale securities,
net of taxes of: $(0.1) for 2004 and $0.0 for 2003
229.215.
Total comprehensive income
(6.(1.9)
223.213.
FERC FORM NO.ED. 12-88 Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 11 - Subsequent Events
PacifiCorp appointed Ronnie Mercer to the position of Executive Vice President, Operations, effective January 1, 2005.
On January 20, 2005, PacifiCorp s Board of Directors declared a dividend on common stock of $0.155 per share totaling $48.3 million
and payable on February 28,2005.
FERC FORM NO.ED. 12-Page 123.
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, A D HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
Year/Period of Report
End of 2004/04
Name of Respondent
PacifiCorp
2. Report in columns (t) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges , report the accounts affected and the related amounts in a footnote.
Line
No.
Item Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Minimum Pension
Liability adjustment
(net amount)
(c)
Foreign Currency
Hedges
Other
Adjustments
(a)
1 Balance of Account 219 at Beginning of
Preceding OuarterIYear
2 Preceding QuarterIYear Reclassification
from Account 219 to Net Income
3 Preceding QuarterIYear Changes in Fair
Value
4 Total (lines 2 and 3)
5 Balance of Account 219 at End of
Preceding QuarterIYear / Beginning of
6 Current QuarterIYear Reclassifications from
Account 219 to Net Income
7 Current OuarterIYear Changes in Fair Value
8 Total (lines 6 and 7)
9 Balance of Account 219 at End of Current
QuarterlY ear
(d)(e)
39,538)
39,538)
135 429
135,429
507)
507)
516)998,159
FERC FORM NO.1 (NEW 06-02)Page 1228
Name of Respondent This ~rt Is: Date of Report Year/Period of Report(1) ~ An Original (Mo, Da, Yr) End of 2004/04PacifiCorp (2) A Resubmission 04/25/2005
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, A D HEDGING ACTIVITIES
Line
No.
Other Cash Flow
Hedges
Interest Rate Swaps
Other Cash Flow
Hedges
(Specify)
Totals for each
category of items
recorded in
Account 219
(h)
955,259
(f)
(g)
095,891
095,891
051 150
61,507)
61,507)
989 643
FERC FORM NO.1 (NEW 06-02)Page 122b
Net Income (Carried
Forward from
Page 117, Line 72)
Total
Comprehensive
Income
(i)
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
This f3!port Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
SUMMA Y OF UTILITY PLANT AND ACCUM LATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in
column (f) common function.
(a)
Total Company for the
Current Year/Ouarter Ended
(b)
Electric
(c)
Line
No.
Classification
1 Utility Plant
2 In Service
3 Plant in Service (Classified)
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (3 thru 7)
9 Leased to Others
13,688 184 361
296,281
213,554
13,688,184 361
296.281
213,554
712 694 196 13,712 694 196
10 Held for Future Use
11 Construction Work in Progress
12 Acquisition Adjustments
13 Total Utility Plant (8 thru 12)
14 Accum Prov for Depr, Amort, & Depl
15 Net Utility Plant (13 less 14)
16 Detail of Accum Prov for Depr, Amort & Depl
17 In Service:
18 Depreciation
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utility Plant
22 Total In Service (18 thru 21)
23 Leased to Others
346,101
439,891 117
157 193 780
311 125 194
860,338 936
450 786 258
346 101
439,891,117
157 193 780
14,311 125,194
860,338,936
450 786 258
24 Depreciation
25 Amortization and Depletion
26 Total Leased to Others (24 & 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,31,32)
930 108
860,338 936
68,930 108
860,338 936
FERC FORM NO.1 (ED. 12-89)Page 200
Gas
This F3!1?ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Other (Specify) Other (Specify) Other (Specify)
Year/Period of Report
End of 2004/04
Name of Respondent
PacifiCorp
Common Line
No.
(d)(e)(f)
FERC FORM NO.1 (ED. 12-89)Page 201
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Oa, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
ELECTRII; PLANT IN SERVICE (Account 101 , 102, 103 and 106)
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;
Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount
of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)
.lne Account 1:S~lanCe Additions
No.Beginning of Year
(a)(b)(c)
1. INTANGIBLE PLANT
(301) Organization 26,288,163
(302) Franchises and Consents 915,296 86,556,030
(303) Miscellaneous Intangible Plant 485,788,559 923,546
TOTAL Intangible Plant (Enter Total of lines 2 , and 4)531 992 018 121,479 576
2. PRODUCTION PLANT
A. Steam Production Plant
(310) Land and Land Rights 80,417 641 886,166
(311) Structures and Improvements 761 253 198 607 043
(312) Boiler Plant Equipment 2,461 440 363 71,416 214
(313) Engines and Engine-Driven Generators
(314) Turbogenerator Units 670,649,025 047 316
(315) Accessory Electric Equipment 324 257 633 263 905
(316) Misc. Power Plant Equipment 931 821 617 359
(317) Asset Retirement Costs for Steam Production 15,526,296 996,037
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)343,475.977 120 834 040
B. Nuclear Production Plant
(320) Land and Land Rights
(321) Structures and Improvements
(322) Reactor Plant Equipment
(323) Turbogenerator Units
(324) Accessory Electric Equipment
(325) Misc. Power Plant Equipment
(326) Asset Retirement Costs for Nuclear Production
TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
C. Hydraulic Production Plant
(330) Land and Land Rights 20,537,840 937
(331) Structures and Improvements 710,372 722 361
(332) Reservoirs, Dams, and Waterways 275 618 218 10,155,484
(333) Water Wheels, Turbines, and Generators 629,336 049 360
(334) Accessory Electric Equipment 308 479 383,861
(335) Misc. Power PLant Equipment 127 938 029
(336) Roads, Railroads, and Bridges 080,147 609 770
(337) Asset Retirement Costs for Hydraulic Production 934,446 321 763
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)506,946,776 22,667 039
D. Other Production Plant
(340) Land and Land Rights 842 880
(341) Structures and Improvements 15,751 405 652,942
(342) Fuel Holders, Products, and Accessories 404 442 138
(343) Prime Movers 178 925 039 173,956
(344) Generators 371 959
(345) Accessory Electric Equipment 679,158 758,088
(346) Misc. Power Plant Equipment 534,784
FERC FORM NO.1 (REV. 12-03)Page 204
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04
(2) 0 A Resubmission 04/25/2005
ELECTRIC PLANT IN SERVICE (Account 101,102,103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent's plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date
Line(d) (e) (f) End f Year No.
26,288,163
106,471 326
41,379,027 425,875 478 907 203
41,379,027 425,875 611,666,692
60,107 119,867 81,363 567
778,574 57,719 767 023,948
839,353 587 579 493,429,645
11 ,894,404 341,472 688,143,409
355,848 128,340 326,037 350
338,091 646,615 25,564 474
25,522 333
53,266,377 958,914 407,084 726
763,889 595 19,769,293
749,173 77,683,560
13,365 538 272,408,164
801,092 79,877 604
696,775 540,544 38,455,021
721 184,246
239 273 12,450,644
612,683
19,624 461 548,139 509 441 215
516,624 359,504
440,257 844 604
63,264 492 844
148 752,441 178,341 406
161,459 61,533,418
151 16,487 397
534 784
FERC FORM NO.1 (REV. 12-03)Page 205
Name of Respondent This (!)ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04(2) D A Resubmission 04/25/2005
ELECTRIC PLANT IN SERVICE (Account 101 102 103 and 106) (Continued)
Retirements Adjustments Transfers Balance at Line
End ~f Year No.
(d)(e)(f)
492 532
148 479,314 281 086,489
72,895,986 027 739 197,612,430
146,855 160 078 88,520 326
51,880 211 024 48,878 361
356,170 562,496 868,988,467
644 195 361 139,132
200,973 754 868 484 345 795
463,423 92,472 618 116 181
367 203
132 951 434
370 173
270,433 493,349 487 677,072
247 -21 075 183,599
120 687 610 36,347,414
738,311 358,826 615,480,059
260 129 634 744 285,090
212 599 559,313,562
527,522 235,872 409
154 631 7,433 553,777 450
289 921 848 847 249
528,235 387,957,405
177 433 181,525,187
170 983 867
49,658
858,930 53,596 614
908,248 274 642 257 219,563
239 422 881 163
874 447 194,208 212 985,408
074 598 140 347 116 229 400
245 153 159,185 80,511 775
192 844 318,509 340,986
234,791 93,300 504 702
416 968 067 781
826,129 439,573 105,964 582
500,544 824 329 224 727 448
93,524 566 613 779
116 685 138 431 861 827 024
9f3891~
",......,:,.
52,085,599 889 093 134,008,604
205 539 293 216 772 13,688 184 361
1~~tQ
205,539 293 474 079 216,772 13,688,397 915
FERC FORM NO.1 (REV. 12-03)Page 207
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
EL ~CTRIC PLANT HELD FOR FUTURE USE (Account 105)
1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more.Group other items of property held
for future use.
2. For property having an original cost of $250 000 or more previously used in utility operations, now held for future use, give in column (a), in addition to
other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line Description and Location Date Orl~lnalfY TncTuaea -U-ate Expected to be used Balance at
No.Of prorerty
in T is Account in UtilitY Service End of Year
(b)(c)(d)
Land and Rights:
North Horn Mountain Coal Properties 1977 953,014
Southeast Substation 1975 273 612
Miscellaneous, each under $250,000 979
Other Property:
Miscellaneous, each under $250,000 112,496
Total 346 101
FERC FORM NO.1 (ED. 12-96)Page 214
lank Page
(Next Page is: 216)
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
CONSTRUCTION WORK IN PROGRESS - - ELEC TRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100,000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
Intangible:
Klamath Relicensing 205 353
EMS/SCADA Phase II 18,968 475
Lewis River Relicensing 341 721
Merwin Relicensing 769,068
Swift Relicensing 364,948
Rogue Relicensing 644 948
IS SAP Licenses 751,167
ER K2 CIC087 KW Commercial Risk System 341 494
Production:
Currant Creek Power Project 186 903 611
Lake Side Capital Build 307 100
Replace Prospect Flumes 3,402,262
Carbon U1 Turbine Blade Replacement 135,316
Swift No.1 Capacity Retention 040 553
Colstrip: Plant Control Sys Upgrade 871 768
Hunter U1 Submerged Flight Conveyor 579 248
Gen Resource Dev. CAI Project 357 785
Oneida #2 Generator Shaft & Runner Replacement 268,347
Huntington Coal Blending Ash Analyzer 193,287
Jim Bridger U2 Controls Upgrade 068,908
Wyodak U1 Controls Upgrade 023,766
Transmission:
Terminal-Tooele 138kV Rebuild 103,485
Syracuse Add 345-138kV Transformer (394MVA)090,683
Currant Creek Substation 921 095
Taylorsville-West Valley 138kV Rbld Ph 2 302 527
Camp Williams-Mona #1 Reconductor 6.020,384
WW-H Canyon 230 Ln:Repl Pole (Clmb Insp)271 266
Swift 1-Replace Breakers 082 961
Distribution:
Jordanelle Sub New 138-12.5kV Sub 564,369
West Ogden install 2nd transformer (30MVA)156,672
Shevlin Park New Sub & 2 Feeders 880 410
Southeast #4 Inst New 138-12.5kV Sub 494 188
Farmington Convert to 138kV (4.6MV A)794 844
So Weber New 138-12.5kV (30MVA)1,488,399
Roxy Ann Substation New Sub 1,476,693
Manila Inst New 138-12.5kV Sub 167 091
TOTAL 439 891 117
FERC FORM NO.1 (ED. 12-87)Page 216
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
CONSTRUCTION WORK IN PROGRESS - - ELE( TRIC (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $100 000, whichever is less) may be grouped.
Line Description of Project Construction work in progress -
No.Electric (Account 107)
(a)(b)
Distribution Continued:
UDOT Highway Relo Smithfield to Idaho St Line 053,087
General:
West Valley-Aspen Replace Microwave 891 864
Data Network Equipment Obsolescense 193 611
SL Area Install Fiber Optic Comm Ph1 153,708
101,244 655
TOTAL 439 891 117
FERC FORM NO.1 (ED. 12-87)Page 216.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Section A. Balances and Changes During Year
....Ine Item
~~~)
Efe
cg~lcflant In
t:.lecmc t"'lam. !1elo t:.lecglc I 'Omt
No.ervlce for Future Use Lease to t erg
(a)(b)(c)(d)(e)
1 Balance Beginning of Year 232,423,332 232,375,802 47,530
Depreciation Provisions for Year, Charged to
(403) Depreciation Expense 360 452 077 360 452,077
(403.1) Depreciation Expense for Asset
Retirement Costs
(413) Exp. of Elec. PIt. Leas. to Others
Transportation Expenses-Clearing
Other Clearing Accounts
8 Other Accounts (Specify, details in footnote):25,627 512 720
TOTAL Deprec. Prov for Year (Enter Total of 386,082 309 386,079,589 72C
lines 3 thru 9)
Net Charges for Plant Retired:
Book Cost of Plant Retired 162 930,492 162,930,492
Cost of Removal 23.652 435 23,652 435
Salvage (Credit)985 394 985 394
TOTAL Net Chrgs. for Plant Ret. (Enter Total 179,597 533 179,597 533
of lines 12 thru 14)
Other Debit or Cr. Items (Describe, details in 560,887
footnote): '.
Book Cost or Asset Retirement Costs Retired
Balance End of Year (Enter Totals of lines 1 5,463 468 995 463,418,745 250
15, 16, and 18)
Section B.Balances at End of Year According to Functional Classification
Steam Production 194 354 359 194,354 359
Nuclear Production
Hydraulic Production-Conventional 221 888 229 221,888,229
Hydraulic Production-Pumped Storage
Other Production 162 163 162,163
Transmission 936,423,808 936,373,558 250
Distribution 593,449 584 593,449 584
General 463 190 852 463,190 852
TOTAL (Enter Total of lines 20 thru 27)463 468 995 463,418 745 50,250
FERC FORM NO.1 (REV. 12-03)Page 219
Blank Page
(Next Page is: 224)
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
INVESTM NTS IN SUBSIDIARY COMPANIES Account 123.
1. Report below investments in Accounts 123., investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418.
Line Description of Investment Date Acquired Date Of Amount of Investment at
No.(a)(b)(~ity Beginning of Year
(d)
PACIFIC POWER & LIGHT COMPANY
Common Stock 100
SUBTOTAL 100
CENTRALIA MINING COMPANY
Capital Contributions 000
SUBTOTAL 000
ENERGY WEST
Capital Contributions 000
SUBTOTAL 000
PMI - BRIDGER COAL COMPANY
Common Stock
Capital Contributions 960,861
SUBTOTAL 960 862
GLENROCK COAL
Common Stock
SUBTOTAL
INTERWEST MINING
Common Stock 000
SUBTOTAL 000
PACIFICORP ENVIRONMENTAL REMEDIATION COMPANY
Capital Contributions 900 000
Equity in Earnings 023 935
SUBTOTAL 923,935
PACIFIC FUTURE GENERATIONS INC
Equity in Earnings 901
SUBTOTAL -3,901
Total Cost of Account 123.1 $464 9361 TOTAL 68,883,997
FERC FORM NO.1 (ED. 12-89)Page 224
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)
End of 2004/04(2) 0 A Resubmission 04/25/2005
INVESTMENT~ IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (1) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or
the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible
in column (f).
8. Report on Line 42, column (a) the TOTAL cost of Account 123.
Equity In Subsidiary Revenues for )rear Amount oTlnvestment at Gain or Loss from Investment Line
Earnin~s of Year (f)
End ftf Year Dis
p?fi)ed of No.
100
100
000
000
000
000
343 446 617,415
343,446 60,617,416
000
000
944,419 844,419
813 785 837 720
813,785 944,419 682 139
163 -3,738
163 738
813 948 399 027 69,298 918
FERC FORM NO.1 (ED. 12-89)Page 225
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2004/04(2)D A Resubmission 04/25/2005 End of
MATERIALS AND SUPPLIES
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
Line Account Balance Balance Department or
No.Beginning of Year End of Year Departments which
Use Material
(a)(b)(c)(d)
Fuel Stock (Account 151)53,546,693 450,942 Electric
Fuel Stock Expenses Undistributed (Account 152)
Residuals and Extracted Products (Account 153)
Plant Materials and Operating Supplies (Account 154)
Assigned to - Construction (Estimated)32,845,825 548,576 Electric
Assigned to - Operations and Maintenance
Production Plant (Estimated)46,049,879 49,279 721 Electric
Transmission Plant (Estimated)872 102 754 364 Electric
Distribution Plant (Estimated)139 846 466 633 Electric
Assigned to - Other (provide details in footnote)643 198 197 323 Electric
TOTAL Account 154 (Enter Total of lines 5 thru 10)550,850 105,246,617 Electric
Merchandise (Account 155)
Other Materials and Supplies (Account 156)
Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
Stores Expense Undistributed (Account 163)
TOTAL Materials and Supplies (Per Balance Sheet)145,097 543 153,697 559
FERC FORM NO.1 (ED. 12-96)Page 227
Blank Page
(Next Page is: 228)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)2004/04
(2)0 A Resubmission 04/25/2005 End of
Allowances (Accounts 158.1 and 158.
1. Report below the particulars (details) called for concerning allowances.
2. Report all acquisitions of allowances at cost.
3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General
Instruction No. 21 in the Uniform System of Accounts.
4. Report the allowances transactions by the period they are first eligible for use: the current year s allowances in columns (b)-(c),
allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining
succeeding years in columns G)-(k).
5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.
line Allowances Inventory Current Year 2005
No.(Account 158.No.Amt.No.Amt.
(a)(b)(c)(d)(e)
Balance-Beginning of Year 188,860.00 90,032.
Acquired During Year:
Issued (Less Withheld Allow)
Returned by EPA
Purchases/Transfers:
Total
Relinquished During Year:
Charges to Account 509 640.
Other:
Cost of Sales/Transfers:
Total
Balance-End of Year 89,089.90,053.
Sales:
Net Sales Proceeds(Assoc. Co.
Net Sales Proceeds (Other)
Gains
Losses
Allowances Withheld (Acct 158.
Balance-Beginning of Year 259.259.
Add: Withheld by EPA
Deduct: Returned by EP A 259.
Cost of Sales
Balance-End of Year 259.
Sales:
Net Sales Proceeds (Assoc. Co.
Net Sales Proceeds (Other)259.
Gains 259.
Losses
FERC FORM NO.1 (ED. 12-95)Page 228
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/25/2005
Allowances (Accounts 158.1 and 158.2) (Continued)
6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA's sales of the withheld allowances. Report on Lines
43-46 the net sales proceeds and gainsllosses resulting from the EPA's sale or auction of the withheld allowances.
7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identity associated companies (See "associated
company" under "Definitions" in the Uniform System of Accounts).
8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identity associated companies.
9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers.
10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.2006 2007 Future Years TotalsNo. AmI. No. AmI. No. AmI. No. AmI.(f)
(g)
(h) (i) 0) (k) (I) (m)
774.00 100,331.00 3 943,437.00 4400 434.00 Line
No.
795.00 100,352.00 4 100 338.00 4 457 627.00
528.00 4,528.00
2,269.00 4 528.00
259.00 2,259.00 113,180.00 119 957.00
2,2~OO
259.00
97,640.
FERC FORM NO.1 (ED. 12-95)Page 229
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/Q4(2) 0 A Resubmission 04/25/2005
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.
Line Description of Unrecovered Plant rotal Costs WRITTEN OFF DURING YEAR Balance atNo.and Regulatory Study Costs (Include Amount Recognisedin the description of costs, the date of of Charges During Year Account Amount End of Year
Commission Authorization to use Acc 182.Charged
and period of amortization (mo, yr to mo, yr)J
(a)(b)(c)(d)(e)(f)
Unrecovered Plant: Trojan Nuclear 863,612 407 674 863 10,188,749
Plant located near Portland, OR
Date of Retirement: 12/31/1992
Date of Commission Authorization:
04/20/1993
Amortization Period: 01/1993
through 01/2011
Unrecovered Plant: Trail Mountain 934 235 151 304 104 630,131
Date of Retirement: 03/15/2001
Date of Commission Authorization:
04/04/2002 - UT
OS/20/2002 - OR
04/26/2001 - WY
04/26/2001 - ID
Amortization Period: 04/2001
hrough 03/2006
TOTAL 23,797,847 978,967 16,818,880
FERC FORM NO.1 (ED. 12-88)Page 230b
lank Page
(Next Page is: 232)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) Ei A Resubmission 04/25/2005
0 HER REGULATORY ASSETS (Account 182.
1. Report below the particulars (details) called for conc~rning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $50,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line Description and Purpose of Balance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of Written on uunng Written on uunng Current OuarterNear
Current the Ouarter/Year the Period
OuarterNear Account Charged Amount
(a)(b)(c)(d)(e)(f)
Demand Side Resources:
California
Revenue Recovery Balancing Act 369 570)95,855 273,715
DSM Reg Assets All Less Than $50,000 627 908 60,013 614
Idaho
101302 Super Goodcents 1990 (12)026 908 171 855
101303 Super Goodcents 1991 (12)120,901 908 20,151 100,750
101304 Super Gooclcents 1992 (12)217 814 908 303 181 511
101305 Weatherization Cash Grants 1993 (12)475,774 908 79,296 396,478
101314 Cash Grant 1990 (12)900 908 983 917
101324 Discount Early Loan Payoff 1992 (12)343 752 908 292 286,460
101330 Regional Mobile Home (MAP) 1993 (12)256,679 908 780 213,899
101331 Regional Mobile Home (MAP) 1994 (12)141 431 908 572 117 859
101332 Regional Mobile Home (MAP) 1995 (12)555 908 926 59,629
101333 Regional Mobile Home (MAP) 1996 (12)208,941 908 824 174 117
101370 NEEA 1998 (12)101 852 908 551 301
101374 Super Gooclcents 1993 (12)151 426 908 238 126 188
101375 Super Goodcents 1994 (12)129,767 908 627 108,140
101376 Super Goodcents 1995 (12)368 908 12,394 974
101914 NEEA 1999 (12)257 440 908 180 225,260
101955 NEEA 2000 (12)234 173 908 019 208 154
102079 NEEA 2001 (12)224 952 908 495 202 457
102184 NEEA2002 232,247 908 21,113 211 134
102219 Industrial Finanswer 2003 190,820 908 15,902 174 918
102221 NEEA2003 424 655 908 35,388 389,267
1 02263 Irrig~tion Interruptible 2003 289,240 908 103 265,137
101391 DSR Carrying Charge 672.778 908 278,796 393,982
102352 Industrial Finanswer 2004 100,455 100455
102354 NEEA20O4 207 319 207319
102356 Irrigation Interruptible 2004 296,601 296,601
DSM Reg Assets All Less Than $50,000 684 394 755 908 99,498 662 651
Oregon
101998 Oregon Decoupling 2000/2001/2002 287 142)908 287,142)
102203 Oregon Rev. Recovery Offset 182.392 475 220 908 475 220
102249 Regulation Carrying Chrg Adjmt 172,287 456 172 287
102250 Regulation Delayed Amort Adjmt 449 416 456 449,416
102251 Regulation NLR Adjustment 466439)466,439
102252 Regulation Incentives Adjustment 156,505)156,505
102253 Regulation Renewable Adjustment 423,857 456 423,857
102254 Regulation Oregon Exp Adjustment 32,606 456 32 ,606
TOTAL 573 981 490 179 420-408,098 170 191 062 740
FERC FORM NO.1/3-Q (REV. 02-04)Page 232
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04
(2) 0 A Resubmission 04/25/2005
0 HER REGULATORY ASSETS (Account 182.
1. Report below the particulars (details) called for conc~rning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $50 000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line Description and Purpose of Balance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of -wntfen ott uunng written ott uurlng Current QuarterNear
Current the QuarterlYear the Period
QuarterlYear Account Charged Amount
(a)(b)(c)(d)(e)(f)
Utah
101182 Industrial Finanswer 1993 (15)78,052 908 611 62,441
101183 Industrial Finanswer 1994 (15)131 054 908 843 109,211
101184 Industrial Finanswer 1995 (15)149,621 908 374 128,247
101185 Industrial Finanswer 1996 (15)209 908 10,276 71,933
101200 RFP CES/WAY 1996 (10)100,080 908 33,360 66,720
101214 Energy Finanswer 1992 (15)125,548 908 31,387 161
101215 Energy Finanswer 1993 (15)302,249 908 60,450 241 799
101216 Energy Finanswer 1994 (15)417,903 908 651 348,252
101217 Energy Finanswer 1995 (15)292214 908 745 250,469
101218 Energy Finanswer 1996 (15)198,593 908 824 173,769
101221 Commercial Competitive 1993 (15)98,046 908 19,609 78,437
101249 RFP EUA Onsite 1995 (10)299,676 908 149838 149,838
101250 RFP EUA Onsite 1996 (10)167364 908 55,788 111,576
102131 Energy Finanswer 200112002 280,484 280,484
102133 Industrial Finanswer 2001/2002 353,184 353,184
102138 Compact Fluorescent Lamps 2001/2002 201,685 201 665
102147 Commercial Small Retrofit 2001/2002 847 943 847,943
102149 Commercial Retrofit Lighting 2001/2002 497,810 497 810
102150 Industrial Retrofit Lighting 2001/2002 799 81,799
102195 Industrial Retrofit Lighting 2002 70,546 70,546
102196 Power Forward 2002 115,022 115,022
102146 UT Carrying Charge 2001/2002 1,408274 601 318 009,592
101663 Utah Net Lost Rev. Comm. Fin 1995 146,548 908 20,936 125,612
101664 Utah Net Lost Rev. Comm. Fin 1996 923 908 10,490 73,433
101679 Utah Net Lost Rev. Major Accounts 1996 152,152 908 50,717 101,435
101680 Utah Net Lost Rev. Major Accounts 1997 68,419 908 105 314
101683 Utah Net Lost Rev. Comm. Spec. 1996 171,355 908 21,419 149,936
101695 Utah Net Lost Rev. EF Custom 1996 79,689 906 961 69,728
101696 Utah Net Lost Rev. EF Custom 1997 79,426 908 825 70,601
102213 Refrigerator Recycling pgm. 2003 508,751 508,751
102223 AlC Load Control - Residential. 2003 460,332 460,332
102225 Air Conditioning. 2003 563,568 563568
102226 Commercial Retrofrt Lighting. 2003 186,577 186,577
102227 Commercial Small Retrofit .2003 894,606 894606
102229 Energy Finanswer . 2003 541 964 541,964
102230 Industrial Finanswer. 2003 658,473 658 473
102231 Industrial Retrofit Lighting. 2003 190 999 190,999
102337 Refrigerator Recycling Program. 2004 581 306 581 ,306
102338 AlC Load Control. Residential. 2004 910,095 910,095
102339 Air Conditioning. 2004 026,027 026,027
102340 Commercial Retrofit Lighting. 2004 547,346 547,346
102341 Commercial Small Retrofit. 2004 284,669 284,669
TOTAL 573,981 490 179 420-408 098,170 191,062,740
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
0 HER REGULATORY ASSETS (Account 182.
1. Report below the particulars (details) called for conc~rning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $50,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line Description and Purpose of Balance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of Written on uunng wntten OTT uunng Current OuarterlYear
Current the OuarterlYear the Period
OuarterlYear Account Charged Amount
(a)(b)(c)(d)(e)(f)
102343 Energy Finanswer - 2004 226734 226,734
102344 Industrial Finanswer. 2004 561,668 561 668
102345 Industrial Retrofit Lighting - 2004 230 152 230,152
102346 Industrial Small Retrofit - 2004 263 263
102347 Power Forward - 2004 64 ,000 54,000
102348 Commercial Self-direct. 2004 88,703 88,703
102349 Industrial Self-direct - 2004 129038 129 038
102444 Residential New Construction - 2004 76,332 76,332
102460 Commercial Finanswer Express - 2004 445,949 445,949
102461 Industrial Finanswer Express - 2004 146022 146,022
102462 Utah Revenue Recovery - SBC Offset ( 21 073,192)073,192
DSM Reg Assets All Less Than $50,000 320,681 824 908 611 305 755,200
Washington
102030 Energy Finanswer 359367 563,479 922,846
102032 Industrial Finanswer 230820 217353 448 173
102033 Low Income 262,663 132 276 394 939
102036 Commercial Small Retrofit 651 449 135,418 786,867
102038 Commercial Retrofit Lighting 466,558 157,804 624,362
102040 NEEA 338,152 263866 602 018
102044 Home Comfort 653 353 127 006
102072 CFL Bulbs 182804 182,804
102185 Web Audit Pilot 381 216 125,092 506,308
102128 SBC Rev. Recovery ( 13033 637)( 4 691 081)17,724,718
102188 Carrying Charge Penalty 678)833)-12 511
102206 School Energy Education 123,022 253,252 376 274
102039 Industrial Retrofit Lighting 748 30 . 385 60,133
102458 Commercial Finanswer Express 131 226 131,226
DSM Reg Assets All Less Than $50,000 331 180 908 162 760 168,420
Wyoming
102069 Industrial Finanswer2001 (10)83,525 908 441 73,084
DSM Reg Assets All Less Than $50,000 432.989 926 908 119,915 376,000
Other Regulatory Assets
Transition Plan - ID (5)800,895 930.103,906 696,989
Transition Plan - OR (10)727239 930.915 664 811,585
Transition Plan - UT (5)626416 930.841 063 785,353
Transition Plan - WY West (5)718616 930.403,339 315 277
Transition Plan - WY East (5)061 206 930.279,442 781 764
FAS 109 Deferred Income Taxes Electric 536 056 206
3, 197'924
35,068,705 500,987 501
SB 1149 Implementation Costs OR Retail Access 794 152 227974 764 102
TOTAL 573 981 490 179 420-408,098 170 191 062,740
FERC FORM NO.1/3-Q (REV. 02-04)Page 232.
Name of Respondent This ~)Qrt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04
(2) 0 A Resubmission 04/25/2005
0 HER REGULATORY ASSETS (Account 182.
1. Report below the particulars (details) called for conc~rning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $50,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Line Description and Purpose of Balance at Debits CREDITS Balance at end of
No.Other Regulatory Assets Beginning of Written off During Written OIT uurlng Current QuarterlYear
Current the QuarterlY ear the Period
QuarterlY ear Account Charged Amount
(a)(b)(c)(d)(e)(f)
Y2K Expense 98-00 OR (7)268,659 316,906 930.263,084 322,481
98 Early Retirement OR 707787 930.676,947 030,840
BSIP/SAP UT (4)573 930.573
Glenrock Mine Excluding Reclamation UT (10)638,420 930.302,399 336 021
Software Writedown 1997 UT (4)385,773 930.385,773
Software Writedown 1999 UT (4)275,267 930.275267
Transition Team Costs UT (4)364,428 9302 364,428
94-98 Fed/State Income Tax Audit Payments-317,438 002,682 314 756
Deferred Excess Net Power Costs OR UM995 64,808,372 927 457 25,880,915
Deferred Excess Net Power Costs UT 736,665 486 737 151
Deferred Excess Net Power Costs ID 248,264 248,264
., "
""'_w",,"',,om..",
Deferred Excess Net Power Costs OR UE116 370,070 843 421 285,127 116 786
Environmental Costs (10)043,301 528,073 925 632,695 938,679
Deferred Cost of TOU Guarantee 591 151 742
Deferred Intervenor Funding Grants 103,788 84,563 188 351
IDAI Costs No. CA Direct Access 637 765 407.333,105 304,660
Cholla Plant Transaction Costs (26)15,246,273 557 122,425 14,123 848
Washington Colstrip #3 (22)891 575 456.188 839 387
Cholla Plant Transaction Costs OR 730,961)53,813 677 148
Cholla Plant Transaction Costs WA ( 1 317668)006 220,662
Cholla Plant Transaction Costs ID 447887)973 414 914
Trail Mountain Mine Closure Costs 878,003 151 268 018 609 985
FAS133 Derivative Net Regulatory Asset 526 897,468 249,032 895 277,864 573
FAS 87/88 Pension UT 12,636,056 930.159,014 9,477 042
Noell Kempf CAP UT 554 930.34,465 089
P&M Strike Amort UT 798,532 930.299 449 499,083
Energy Trust of Oregon SB1149 39,430 13,533 143 430 13,533
BPA Idaho Balancing Account 588,767 607 590 254 315,653 880,704
Retail Access Project INC.829 901 053,421 731 859
Reg Asset Min. Pension Liab. Adj.233,771,982 546,879 226,225,103
UT DSM AC-DLC Program 20)
Sch 292 Def Transition Adj Reg Asset 513)513
Sch 293 Def Transition Adj Reg Asset 546)546
Sch 292 Small Non-Res SB1149 Adj Bal Acct 546 182.546
Sch 293 Large Non-Res SB1149 Adj Bal Acct 513 182.513
Asset Retirement Obligations Regulatory Difference 113 140 098,852 24,211,992
DSM Regulatory Assets - Cony 128,728 128 728
DSM Regulatory Assets - Reclass 284 163)284 163
Trail Mountain Mine - Deseret Settlement 251 547 143 001 750 750,203
TOTAL 573,981 490 179,420-408,098,170 191 062 740
FERC FORM NO.1/3-Q (REV. 02-04)Page 232.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) D A Resubmission 04/25/2005
M SCELLANEOUS DEFFERED DEBITS (Account 186)
1. Report below the particulars (details) called for conc~rning miscellaneous deferred debits.
2. For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1 % of the Balance at End of Year for Account 186 or amounts less than $50,000, whichever is less) may be grouped by
classes.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year ~ccoum Amount End of Yearchar
8ed(a)(b)(c)(e)(f)
Mill Fork Mine Rights
Lease Payments 234,050 101 234 050
Joseph Settlement (20)934 780 557 137 381 797 399
Firth Cogeneration Buyout (10)888,160 557 444 080 444 080
Lacomb Irrigation (24)826,770 557 45,720 781 050
Sales of Electric Utility
Facilities and Properties 262,737 various 180,033 82,704
Bogus Creek (42)1,489,520 557 41 ,280 1 ,448,240
Bogus Creek settlement (7)354,000 236,000 118,000
Intangible Pension Asset:
SERP Plan 260 000 228.652 000 608 000
Pension Intangible Asset 42,480 000 228.304 000 176 000
Business Energy Tax Credit:
Wz Tax Credit Loan Prog. (13)922 421 922
EnerQY Finanswer (13)80,002 421 80,002
Industrial Finanswer (13)605,329 421 605 329
Cash Rebate/Incentive (13)232,647 421 232 647
Commercial Retrofit (6)265 794 421 265,794
Industrial Retrofit (6)23,282 421 23,282
Commercial Small Retrofit (6)161 115 421 161 115
Industrial Small Retrofit (6)895 421 895
Tri-State Firm WheelinQ (16)971 ,190 565 971 190
Mead Phoenix Availability
& Trans Charge (50)16,401 080 565 377 760 16,023,320
Financing Costs Deferred 238 159 930.229,870 289
Buffalo Settlement (7)410 557 410
Lakeview Buyout (13)220,005 557 43,280 176,725
TGS Buyout (20)248 865 557 474 233 391
Hermiston Swap (20)789,623 557 539 573 250,050
Deferred Longwall Costs 720,303 151 115,325 604 978
Misc. Work in Progress
I Deferred~eguratory-comm.000 000Expenses (See pages 350 - 351)
TOTAL 695 115 78,628,533
FERC FORM NO.1 (ED. 12-94)Page 233
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
M SCELLANEOUS DEFFERED DEBITS (Account 186)
1. Report below the particulars (details) called for conc~rning miscellaneous deferred debits.
2. For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1 % of the Balance at End of Year for Account 186 or amounts less than $50,000, whichever is less) may be grouped by
classes.
Line Description of Miscellaneous Balance at Debits CREDITS Balance at
No.Deferred Debits Beginning of Year ~ycount Amount End of Year
Char~ed
(a)(b)(c)(e)(f)
Transition Costs - W A (5)951 200 930.893,506 057,694
Hayden Settlement (6)639,057 151 319,141 319,916
Northwest Power Pool 138 092 566 690 130,402
Other Deferred Debits with
Amounts less than $50,000 18,237 202 757 220,994
Deferred Aquila Streamflow
Hedge Costs 458,330 458,330
Point to Point Transmission 1 ,423,848 173,571 597 419
Deferred Costs Wyodak
Settlement (22)368 454 151 335 182 033,272
Jim Boyd Hydro Buyout (11)835,505 557 860 752 645
Deferred Shelf Registration Cos 161 601 930.770 831
Unamortized Credit Agmt Costs 702,786 632,368 335,154
Unamortized PCRB LOC/SBBPA 266 284 815,651 081,935
Unamortized PCRB Mode Conv Cost 030 203 427 128 040 902,163
Deferred Chrgs-Water Rights 225,880 506 500 104 725,776
Weather Hedge Option Purchases 1,440 000 555 1,440,000
Property Damage Repairs 796 796
Emission Reduction Credits 406 980 406,980
Misc. Work in Progress
Deferred RegUlatory Comm.000 000Expenses (See pages 350 - 351)
TOTAL 695 115 78,628,533
FERC FORM NO.1 (ED. 12-94)Page 233.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
ACCUMULATED DEFERRED INCOME TAX S (Account 190)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes.
2. At Other (Specify), include deferrals relating to other income and deductions.
Ine
No.
Electric
escnptlon an ocatlon
(a)
Other
8 TOTAL Electric (Enter Total of lines 2 thru 7)
9 Gas
Other
TOTAL Gas (Enter Total of lines 10 thru 15
Other (Specify)
TOTAL (Acct 190) (Total of lines 8, 16 and 17)767 958,464
Notes
In 2004, PacifiCorp preformed a study on the accumulated deferred income tax balances. As a result of this
study PacifiCorp adopted a uniform accounting methodology for accumulated deferred income taxes for both FERC
and SEC reporting purposes. For FERC reporting purposes, some reclassifications were made between accumulated
deferred income tax assets account 190 and accumulated deferred income tax liability accounts 282 and 283
(net/gross presentation). The reclassification had a balance sheet only effect. If the results of the deferred
tax study had been applied to calendar year 2003 the ending accumulated deferred income tax liabilities in
account 190 for CY 2003 would have been approximately $844,607,900.
FERC FORM NO.1 (ED. 12-88)Page 234
Blank Page
(Next Page is: 250)
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) LJ A Resubmission 04/25/2005
CAPITAL STOCKS (Account 201 and 204)
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (Le., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Line Class and Series of Stock and Number of shares Par or Stated Call Price at
No.Name of Stock Series Authorized by Charter Value per share End of Year
(a)(b)(c)(d)
Common Stock (Account 201)750,000 000-
(PacifiCorp is a fully owned indirect
subsidiary of Scottish Power)
Common Stock (Mines)
6 TOTAL COMMON STOCK 750 000,000
5% Cumulative Preferred (American Stock Exch.126,533 100.110.
Serial Preferred, Cumulative:500,000
52% Series 100.103.
00% Series 1000
00% Series 100.
00% Series 100.100.
40% Series 100.101.00
72% Series 100.103.
56% Series 100.102.
TOTAL PREFERRED STOCK 626,533
FERC FORM NO.1 (ED. 12-91)Page 250
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
CAPITAL STOCKS (Account 201 and 204) (Continued)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT Line
(Total amount outstanding without reduction AS REACQUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS No.
for amounts held by respondent)
S ha res Amount Sl'1ares Qpst Shares Amount
(e)(f)
(g)
(h)(i)
312 176,089 933,223,674
001 001
312 179,090 933,226,675
126 243 12,624 300
065 206,500
046 804 600
930 593,000
908 190,800
959 595 900
69,890 989,000
84,592 459,200
414 633 463,300
FERC FORM NO.1 (ED. 12-88)Page 251
Name of Respondent This ~)Qrt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) D A Resubmission 04/25/2005
OT ;ER PAID-IN CAPITAL (Accounts 208-211 , inc.
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a
subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 112. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such
change.
(a) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to which related.
(c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end
of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d) Miscellaneous Paid-in Capital (Account 211 )-Classify amounts included in this account according to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
i~e l~r nrgunt
( )
Account 211 Miscellaneous Paid-in Capital
Additional Paid-in Capital
TOTAL 808
FERC FORM NO.1 (ED. 12-87)Page 253
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
CAPITAL STOCK EXPENSE (Account 214)
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
LIne Class and Series of stocK Balance at End of Year
No.(a)(b)
Common Stock 093,939
Preferred Stock:
00% Serial 049
52% Serial 676
72% Serial 30,349
56% Serial 49,071
22 TOTAL 281,084
FERC FORM NO.1 (ED. 12-87)Page 254b
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04
(2) Fi A Resubmission 04/25/2005
LONG-TERM DEBT (Account 221 222, 223 and 224)
Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
In column (a), for new issues, give Commission authorization numbers and dates.
For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
For advances from Associated Companies, report separately advances on notes and advances on open accounts.Designate
demand notes as such.Include in column (a) names of associated companies from which advances were received.
For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
In column (b) show the principal amount of bonds or other long-term debt originally issued.
In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D).The expenses, premium or discount should not be netted.
Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year.Also, give in a footnote the date of the Commission s authorization of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
Bonds: (Account 221)
First Mortgage Bonds:
750% Series due April 1 , 2005 150,000,000 177 203
196,500 D
650% Series due November 1, 2006 200,000 000 185,966
670 000 D
300% Series due September 15, 2008 200,000,000 322 659
288,000 D
271 % Series due October 1, 2010 972 000
978% Series due October 1 , 2011 422,000
900% Series due November 15, 2011 500,000,000 567 009
735,000 D
8.493% Series due October 1 , 2012 19,772,000
797% Series due October 1 2013 16,203 000
45 % Series due September 15, 2013 200,000,000 422,659
232,000 D
~~~~
.~~~;~dlJ~~9Sy~t .~.~i..g~.~~200 000,000 436,261
728,000 D
734% Series due October 1 , 2014 28,218,000
294% Series due October 1 , 2015 946,000
635% Series due October 1, 2016 18,750 000
470% Series due October 1 , 2017 19,609,000
700% Series due November 15, 2031 300,000,000 874 150
864,000 D
...?;,
~pp~~~rt~sdlJ~~49~~). .200 000 000 886,261
722 000 D
86% Series D Medium-Term Notes due Feb. 16 2004 500,000 110
81% Series D Medium-Term Notes due Feb. 16 2004 20,000,000 168,880
79% Series D Medium-Term Notes due Feb. 16 2004 000 000 50,664
75% Series D Medium-Term Notes due Feb. 16,2004 000 000 25,332
75% Series H Medium-Term Notes due Jul. 15,2004 175,000 000 680,166
500,500 D
TOTAL 294 986 000 701 723
FERC FORM NO.1 (ED. 12-96)Page 256
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
LON 3.TERM DEBT (Account 221 , 222, 223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD uu1stanaln Line
Nominal Date Date of (Total amount outstan ing without Interest for Year No.
of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)
(g)
resPy~dent)(i)
040193 040105 040193 040105 150,000,000 125 000
110698 110106 110698 110106 200,000 000 11 ,300,000
091503 091508 091503 091508 200,000 000 623,889
041592 100110 041592 100110 23,599 000 134,931
041592 100111 041592 100111 308,000 198 433
111501 111511 111501 111511 500,000,000 500,000
041592 100112 041592 100112 430,000 032 728
041592 100113 041592 100113 10,099,000 935 781
091503 091513 111501 091513 200,000,000 10,930 278
082404 081514 082404 081514 200 000,000 3,465,000
041592 100114 041592 100114 18,529,000 692,671
041592 100115 041592 100115 31,821 000 747,284
041592 100116 041592 100116 13,373 000 195 170
041592 100117 041592 100117 405,000 258 091
111501 111531 111501 111531 300,000 000 23,100,000
082404 081534 082404 081534 200 000 000 130 000
021492 021604 021492 021604 563
021492 021604 021492 021604 195,250
021492 021604 021492 021604 425
021492 021604 021492 021604 063
071597 071504 071597 071504 365,625
933,071,649 229,563,698
FERC FORM NO.1 (ED. 12-96)Page 257
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
LDNG-TERM DEBT (Account 221 222 223 and 224)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221 , Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission s authorization of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
32% Series E Medium-Term Notes due Sept. 3, 2004 500 000 56,361
11 % Series E Medium-Term Notes due Sept. 24, 2004 500 000 48,846
30% Series E Medium-Term Notes due Oct. 22, 2004 10,000,000 67,576
30% Series E Medium-Term Notes due Oct. 22, 2004 000,000 67,576
66% Series E Medium-Term Notes due Oct. 22, 2004 000 000 745
53% Series E Medium-Term Notes due Oct. 26, 2004 750,000 068
71% Series E Medium-Term Notes due Oct. 27, 2004 000,000 20,273
71% Series E Medium-Term Notes due Oct. 27, 2004 250,000 962
60% Series E Medium-Term Notes due Nov. 1 , 2004 000 000 549
72% Series E Medium-Term Notes due Nov. 2, 2004 500,000 824
43% Series E Medium-Term Notes due Jan. 24, 2005 000,000 333
43% Series E Medium-Term Notes due Jan. 24, 2005 500,000 15,832
34% Series E Medium-Term Notes due Oct. 17 2005 000 000 788
36% Series E Medium-Term Notes due Oct. 17,2005 000,000 788
12% Series G Medium-Term Notes due Jan. 15 2006 100,000,000 679,467
67% Series C Medium-Term Notes due Jan. 10,2007 724 000 36,625
625% Series G Medium-Term Notes due June 1 2007 100 000,000 1 ,267 428
630,000 D
43% Series E Medium-Term Notes due Sept. 11,2007 000,000 15,530
22% Series E Medium-Term Notes due Sept. 18, 2007 500 000 19,412
27% Series E Medium-Term Notes due Sept. 24, 2007 000 000 059
375% Series H Medium-Term Notes due May 15, 2008 200,000,000 1 ,416,179
644 000 D
00% Series H Medium-Term Notes due Jut. 15,2009 125,000,000 976 904
451 250 0
15% Series C Medium-Term Notes due Aug. 9, 2011 000,000 327
95% Series C Medium-Term Notes due Sept. 1 , 2011 000,000 175 398
95% Series C Medium-Term Notes due Sept. 1 2011 000,000 132 118
92% Series C Medium-Term Notes due Sept. 1 , 2011 000 000 188,318
29% Series C Medium-Term Notes due Dec. 30, 2011 000,000 040
26% Series C Medium-Term Notes due Jan. 10 2012 000,000 649
28% Series C Medium-Term Notes due Jan. 10 2012 000,000 297
TOTAL 294 986 000 701 723
FERC FORM NO.1 (ED. 12-96)Page 256.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
LON 3-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427 , interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD u~ISlan~:lIn Line
Nominal Date Date of (Total amount outstan ing without Interest for Year No.
of Issue Maturity Date From Date To reduction for amounts Meld by Amount
(d)(e)(f)
(g)
resPYR)dent)(i)
090492 090304 090492 090304 369 050
092492 092404 092492 092404 337 626
102292 102204 102292 102204 590,083
102292 102204 102292 102204 590,083
110692 102204 110692 102204 309 592
102692 102604 102692 102604 46,278
102792 102704 102792 102704 190,180
102792 102704 102792 102704 206,028
110692 110104 110692 110104 63,333
110292 110204 110292 110204 822
012293 012405 012293 012405 000,000 300
012293 012405 012293 012405 500 000 185,750
101592 101705 101592 101705 000,000 367,000
101592 101705 101592 101705 000,000 368,000
012296 011506 012296 011506 100 000,000 120,000
011092 011007 011092 011007 724,000 439 031
060995 060107 060995 060107 100,000,000 625,000
091192 091107 091192 091107 000 000 148,600
091892 091807 091892 091807 500,000 180 500
092292 092407 092292 092407 000,000 290,800
051298 051508 051298 051508 200 000,000 750,000
071597 071509 071597 071509 125,000,000 750,000
080991 080911 080991 080911 000 000 732 000
081691 090111 081691 090111 000 000 237 500
081691 090111 081691 090111 20,000,000 790 000
081691 090111 081691 090111 20,000,000 1 ,784 000
123191 123011 123191 123011 000,000 248,700
010992 011012 010992 011012 000 000 600
011092 011012 011092 011012 000 000 165 600
933 071 649 229,563,698
FERC FORM NO.1 (ED. 12-96)Page 257.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
LONG-TERM DEBT (Account 221 222,223 and 224)
Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
In column (a), for new issues, give Commission authorization numbers and dates.
For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
For advances from Associated Companies, report separately advances on notes and advances on open accounts.Designate
demand notes as such.Include in column (a) names of associated companies from which advances were received.
For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
In column (b) show the principal amount of bonds or other long-term debt originally issued.
In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission s authorization of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
25% Series C Medium-Term Notes due Feb. 1 2012 000,000 22,946
13% Series E Medium-Term Notes due Jan. 22, 2013 10,000 000 75,827
53% Series C Medium-Term Notes due Dec. 16 2021 15,000,000 115 202
375% Series C Medium-Term Notes due Dec. 31 2021 000,000 38,400
26% Series C Medium-Term Notes due Jan. 7,2022 000 000 33,243
27% Series C Medium-Term Notes due Jan. 10, 2022 000 000 594
05% Series E Medium-Term Notes due Sept. 1 2022 15,000,000 131 471
07% Series E Medium-Term Notes due Sept. 9, 2022 000,000 70,118
12% Series E Medium-Term Notes due Sept. 9, 2022 50,000 000 438,238
11 % Series E Medium-Term Notes due Sept. 9, 2022 12,000 000 105 177
05% Series E Medium-Term Notes due Sept. 14,2022 10,000 000 648
08% Series E Medium-Term Notes due Oct. 14 2022 26,000,000 208,198
08% Series E Medium-Term Notes due Oct. 14 2022 25,000 000 200,190
23% Series E Medium-Term Notes due Jan. 20, 2023 000 000 914
23% Series E Medium-Term Notes due Jan. 20, 2023 000,000 30,331
560 P
26% Series F Medium-Term Notes due July 21 2023 000,000 246 981
26% Series F Medium-Term Notes due July 21 , 2023 000,000 100 622
23% Series F Medium-Term Notes due Aug. 16 2023 15,000,000 137 211
24% Series F Medium-Term Notes due Aug. 16 2023 30,000,000 274 423
75% Series F Medium-Term Notes due Sept. 14 2023 000 000 38,250
75% Series F Medium-Term Notes due Sept. 14,2023 000,000 15,300
72% Series F Medium-Term Notes due Sept. 14 2023 000,000 15,300
75% Series F Medium-Term Notes due Oct. 26, 2023 20,000,000 152 326
75% Series F Medium-Term Notes due Oct. 26, 2023 16,000,000 121 861
26 6.75% Series F Medium-Term Notes due Oct. 26, 2023 12,000,000 396
~tY1~lqI111m~mn;~9!
~:~..
20,000,000 151 025
498,600 D
71% Series G Medium-Term Notes due Jan. 15,2026 100,000,000 904,467
Subtotal - First Mortgage Bonds 496,616,000 255 541
Pollution Control Revenue Bonds:
TOTAL 294 986,000 701 723
FERC FORM NO.1 (ED. 12-96)Page 256.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) LJ A Resubmission 04/25/2005
LON 3-TERM DEBT (Account 221 , 222, 22 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD uutstanCln Line
Nominal Date Date of (Total amount outstan ing without Interest for Year No.
of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)
(g)
reSp?~dent)(i)
011592 020112 011592 020112 000,000 247,500
012093 012213 012093 012213 10,000,000 813,000
121691 121621 121691 121621 000 000 279,500
123191 123121 123191 123121 000,000 418 750
010892 010722 010892 010722 000,000 413,000
010992 011022 010992 011022 OOO,00C 330,800
091892 090122 091892 090122 15,000 000 207,500
090992 090922 090992 090922 000,000 645 600
091192 090922 091192 090922 50,000 000 060,000
091192 090922 091192 090922 000,000 973,200
091492 091422 091492 091422 10,000,000 805 000
101592 101422 101592 101422 26,000,000 100 800
101592 101422 101592 101422 25,000,000 020,000
012093 012023 012093 012023 000,000 411 500
012993 012023 012993 012023 000,000 329 200
072293 072123 072293 072123 000,000 960,200
072293 072123 072293 072123 11 ,000,000 798,600
081693 081623 081693 081623 15,000,000 084 500
081693 081623 081693 081623 30,000,000 172,000
091493 091423 091493 091423 . 5 000 000 337 500
091493 091423 091493 091423 000,000 135 000
091493 091423 091493 091423 000,000 134,400
102693 102623 102693 102623 20,000,000 350,000
102693 102623 102693 102623 000 000 080,000
102693 102623 102693 102623 000,000 810 000
121394 121324 121394 121324 638,750
012396 011526 012396 011526 100,000,000 710,000
144 288 000 204 446,938
933,071 649 229,563,698
FERC FORM NO.1 (ED. 12-96)Page 257.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) Ll A Resubmission 04/25/2005
L JNG- TERM DEBT (Account 221 , 222, 223 and 224)
Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
In column (a), for new issues , give Commission authorization numbers and dates.
For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
For advances from Associated Companies, report separately advances on notes and advances on open accounts.Designate
demand notes as such.Include in column (a) names of associated companies from which advances were received.
For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
In column (b) show the principal amount of bonds or other long-term debt originally issued.
In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D).The expenses, premium or discount should not be netted.
Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense , premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission s authorization of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Series of Obligation, Coupon Rate Principal Amount Total expense
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
Poll Ctrl Revenue Refunding Bonds, Moffat County, CO, Series 1994 655 000 874 159
5/8% Lincoln County, WY, Series due Nov. 1, 2021 300,000 228,980
197 125 D
65% Emery County, Utah, Series due Nov. 1, 2023 500 000 624 793
5/8% Emery County, Utah, Series due Nov. 1 , 2023 16,400,000 625,551
389,500 D
Poll Ctrl Rev Refunding Bonds, Sweetwater County, WY, Series 1994 260 000 510 479
Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1994 190 000 209 777
Poll Ctn Rev Refunding Bonds, Emery County, UT, Series 1994 121 940,000 274 246
Poll Ctrl Rev Refunding Bonds, Carbon County, UT, Series 1994 365,000 206,519
Poll Ctrl Rev Refunding Bonds, Lincoln County, WY, Series 1994 15,060 000 422 858
Poll Ctrl Rev Refunding Bonds, Converse County, WY, Series 1988 000,000
Poll Ctrl Revenue Bonds, Sweetwater County, WY, Series 1984 15,000,000 122 887
105,000 D
Poll Ctrl Rev Refunding Bonds, Lincoln Cnty, WY, Series 1991 000 000 771 836
Poll Ctrl Revenue Bonds, City of Forsyth, MT, Series 1986 500,000 304 824
Environ. Imprvmnt Rev Bonds, Converse County, WY, Series 1995 300,000 132,043
Environ. Imprvmnt Rev Bonds, Lincoln County, WY, Series 1995 22,000,000 404 262
~~...
C?~j~g',
...~.
!~t~~.
.~....~.~.
4fm.QY..R~g~ ..F!~,.
. .
g~13
Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992A 335 000 147 642
Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1992B 305,000 138,478
Poll Ctrl Rev Refndng Bonds, Converse County, WY, Series 1992 485,000 194 271
Poll Ctn Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988B 11,500,000 240,792
Poll Ctrl Rev Refndng Bonds, Sweetwater County, WY, Ser. 1990A 70,000 000 660 750
Poll Ctrl Rev Refunding Bonds, Emery County, UT, Series 1991 45,000,000 872,505
Poll Ctn Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988A 50,000 000 422,443
Poll Ctrl Rev Refndng Bonds, City of Forsyth, MT, Series 1988 45,000,000 380,198
Poll Ctrl Rev Refndng Bonds, City of Gillette, WY, Ser. 1988 41,200,000 351 905
Environ. Imprvmnt Rev Bonds, Sweetwater County, WY, Series 1995 24,400 000 225,000
150% Emery County, Utah, Series due September 1 2030 675,000 556,549
TOTAL 294 986,000 56,701,723
FERC FORM NO.1 (ED. 12-96)Page 256.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) D A Resubmission 04/25/2005
LON 3-TERM DEBT (Account 221,222 223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD uutstan~:JJn Line
Nominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)
(g)
reSP?~dent)(i)
111794 050113 111794 050113 40,655,000 659,957
111593 110121 111593 110121 300,000 477 097
111593 110123 111593 110123 46,500 000 684 518
111593 110123 111593 110123 16,400,000 942,698
111794 110124 111794 110124 260 000 353,414
111794 110124 111794 110124 190 000 139 221
111794 110124 111794 110124 121 940,000 029,891
111794 110124 111794 110124 365,000 155,871
111794 110124 111794 110124 15,060,000 266 119
010188 010114 010188 010114 000 000 680 889
120184 120114 120184 120114 15,000,000 600,831
011791 010116 011791 010116 000,000 641 192
" 120186 120116 120186 120116 500,000 359,718
111795 110125 111795 110125 300,000 224,418
111795 110125 111795 110125 000,000 950 031
092992 040105 092992 040105 335,000 152 762
092992 120105 092992 120105 305,000 103 177
092992 070106 092992 070106 22,485,000 367 952
010188 010114 010188 010114 500,000 278,624
072590 070115 072590 070115 70,000 000 978 249
052391 070115 052391 070115 000 000 083 010
010188 010117 010188 010117 50,000,000 1 ,228,014
010188 010118 010188 010118 OOO,000 040,865
010188 010118 010188 010118 200,000 230 869
121495 110125 121495 110125 400,000 577 961
092496 090130 092496 090130 675,000 779,912
933 071 649 229 563,698
FERC FORM NO.1 (ED. 12-96)Page 257.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
LONG-TERM DEBT (Account 221 222 223 and 224)
Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
In column (a), for new issues, give Commission authorization numbers and dates.
For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
For advances from Associated Companies, report separately advances on notes and advances on open accounts.Designate
demand notes as such.Include in column (a) names of associated companies from which advances were received.
For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
In column (b) show the principal amount of bonds or other long-term debt originally issued.
In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation , such as (P) or (D).The expenses, premium or discount should not be netted.
Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year.Also, give in a footnote the date of the Commission s authorization of treatment other than as
specified by the Uniform System of Accounts.
Line Class and Series of Obligation , Coupon Rate Principal Amount Total expense,
No.(For new issue, give commission Authorization numbers and dates)Of Debt issued Premium or Discount
(a)(b)(c)
178 464 D
Subtotal - Pollution Control Revenue Bonds 738,370,000 773 836
Construction Fund on Deposit with Trustee
TOTAL ACCOUNT 221 234,986,000 56,029,377
Reacquired Bonds: (Account 222)
Advances from Associated Companies: (Account 223)
Other Long-Term Debt: (Account 224)
r$I;~~\S~n~~f.I9Pir 000 000 672 346
TOTAL ACCOUNT 224 60,000,000 672 346
J1l~g~r~,rm.
TOTAL 294 986 000 701 723
FERC FORM NO.1 (ED. 12-96)Page 256.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) D A Resubmission 04/25/2005
LON 3-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
AMORTIZATION PERIOD uutstanaln Line
Nominal Date Date of (Total amount outstan ing without Interest for Year No.
of Issue Maturity Date From Date To reduction for amounts held by Amount
(d)(e)(f)
(g)
reSp?~dent)(i)
738,370 000 20,987 260
086,351
880 571 649 225 434 198
061192 061507 070103 061507 500,000 129,500
500 000 129,500
933 071 649 229 563 698
FERC FORM NO.1 (ED. 12-96)Page 257.
This ~rt Is: Date of Report Year/Period of Report(1) ~ An Original (Mo, Da, Yr) End of 2004/04(2) A Resubmission 04/25/2005
RECONCILIATION OF REP RTED NET INCOME WITH TAXABL INCOME FOR FEDERAL INCOME TAXES
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.
2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a
separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group
member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of
the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Name of Respondent
PacifiCorp
Ine
No.
1 Net Income for the Year (Page 117)
4 Taxable Income Not Reported on Books
8~~t
9 Deductions Recorded on Books Not Deducted for Return
mount
(b)
229 928,124
14 Income Recorded on Books Not Included in Return
15 Regulatory Assets True-up
16 F AS 133 Derivatives
17 FAS 133 Derivatives - Book Unrealized Gain/Loss
19 Deductions on Return Not Charged Against Book Income
121,294
20,935,789
215,741 683
071 306,904
206,107,11127 Federal Tax Net Income
28 Show Computation of Tax:
30 Federal Income Tax at 35.00%
31 Federal Accrual to Return Adjustments
32 ax Reserve Changes
33 ax Reclass
34 Credits
36 Total
72,137 489
253,533
419 000
584 974
700,504
017,478
FERC FORM NO.1 (ED. 12-96)Page 261
Blank Page
(Next Page is: 262)
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
TAXES ACCRUED, PREPAID AND CHAF GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
....
Ine Kind of Tax BALANCE AT BEGINNING OF YEAR ;\,~xes ~ita'Adjust-C argedNo.(See instruction 5)1 axes Accru~(j ~repai51 Taxes ~nng ~ring ments(Account 236)(Include In Account 165)ear ear
(a)(b)(c)(d)(e)(f)
Federal:
Income 17,194 965 017 474 147 807
Unemployment 85,700 260,306 363,892
Unemployment - Energy 249 127 741 165,198
Unemployment - Interwest 669 689
Excise Tax - Coal 337 944 232 821 746
Subtotal 101 140 351 422 500 332 381 191
State:
State Income Taxes 345 231
Subtotal 345,231 345 231
Arizona:
Property 102 100 725 526 867 798
Income 69,215 -124 379 90,692-
Use 241 40,861 45,102
Subtotal 175 556 642 008 003,592 273
California:
Property 809 139
.... ...
583 360 583,845 ..N~pt:m?Q4.
Unemployment 051 051
Bank/Corp. Franchise 181 925 -351,909 256,597
Use 793 96,190 101,745
Regulatory Commission 638 73,686 :~~~i~5~.
Local Franchise 279 487 018 059 729 563
Subtotal 283,344 2,469,389 769,487 791 392
Colorado:
Property 500 000 330,804 330,804
Income 179 66,436 48,442
Subtotal 501 179 264 368 379 246 158
Idaho:
Property 619,159 983,238 930,305
Income 882 269 666 354 485 877 1i~2i
TOTAL 718 526 10,436,368 151 615 364 202 672 678 661,333
FERC FORM NO.1 (ED. 12-96)Page 262
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
TAXES ACCF UED, PREPAID AND CHARGED DU ING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items AOjUstments to ReI.Other No.AcCo
~m 236)
(Incl. in Account 165)(Account 408., 409.(Account 409.Eamlngs (Account 439)
(h)(i)(k)(I)
948 540 160,092
13,834
705
399 689
130 823
106,553 948 540 45,160,092 191 350
959,828 725 526
130 583 136,190
829,245 589 336 672
555,716
616 633 385,326
238
567,983 018,059
191 854 188 449 280 940
500,000 329,760
-105 541 744
394,459 257,016 353
672 092 981 138
811 864 729,630
604 016 49,692 288 125 762 146 25,853,242
FERC FORM NO.1 (ED. 12-96)Page 263
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
TAXES ACCRUED, PREPAID AND CHAI GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual , or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
ILine Kind of Tax BALANCE AT BEGINNING OF YEAR ~~xes
~~~
Adjust-C argedNo.(See instruction 5)Taxes Accru~p Prepatd 1 axes ~rlng ~ring ments
(Account 236)(Include In Account 165)ear ear
(a)(b)(c)(d)(e)(f)
KWh 846 346
Unemployment 320 10,320
Regulatory Commission
.....
125,349 278 991 307 283 3:i~1
Use 436 157,675 150,530
Subtotal 510 864 125,349 780 716 900 661 235,467
8 Montana:
Property 222 462 283 700 365,056
Corporate License 979 111 642 404
Energy License 187 641 131 890
Wholesale Energy 56,504 132 563 150,419
Subtotal 280,945 492 262 728 769 13,709
Nevada:
Unemployment
Other Payroll Taxes 320
Subtotal 386
New Mexico:
Property 694 501 8,444
Subtotal 694 501 444
Oregon:
Property 534 265,891 16,397 520 708 510
Unemployment 1 ,535 840 535 840
Wilsonville Payroll 900 900
Excise 17,261 104 271 390
~~:::
:J IIICity of Portland 305,643 109 644
Office of Energy 382,106 552 507
Tri-Met 994,407 994,407
Lane County 782 782
Franchise 483,461 16,757 439 16,714 600
Undercollected Franchise 000 000 000 000
Regulatory Commission 583 825 368 524 379 599
Multnomah County 726 642
TOTAL 718,526 436,368 151 615,364 202 672,678 661 333
FERC FORM NO.1 (ED. 12-96)Page 262.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
TAXES ACCF UED, PREPAID AND CHARGED DU ~ING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items AdjUstments to Ret.Other No.Acco~nt 236)(Incl. in Account 165)(Account 408.1, 409.(Account 409.Earnings (Account 439)
(h)(i)(k)(I)
500 16,846 iIIIi581
501 037 268,354 512 362
141,106 283,700
177 358 122,243
751 187,641
38,648 132,563
058,147 481.661 10,601
320
320
751 501
751 501
573,347 16,316 362
793,353 771 955
129 516 120 055
170,401 382,106
526 300 757,439
000,000
. g~~~~~?,
31,604 016 49,692 288 125 762,146 25,853,242
FERC FORM NO.1 (ED. 12-96)Page 263.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da. Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
TAXES ACCRUED, PREPAID AND CHAF GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual , or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
ILine Kind of Tax BALANCE AT BEGINNING OF YEAR ~h~xes
~~~
Adjust-C argedNo.(See instruction 5)1axes Accrue9 prepai.d Taxes ~nng ~ring ments
(Account 236)(Include In Account 165)ear ear
(a)(b)(c)(d)(e)(f)
1 Subtotal 22,780 384 849 716 059 484 813 769 470 961
Texas:
Unemployment 379 379
Subtotal 379 379
Utah:
Property 762,447 28,263,247 700 915
Income 509,617 544 095 313,363
Unemployment 242,685 242,685
Interwest Mining Unemploy.567 567
Navajo Nation 276 276
Use 134 887 581,487 481 049
MSHA Assessments 15,483 15,483
Interwest Mining Use
Regulatory Commission 461 303 924 467 926 329
Gross Receipts 783,504 230,289 966,310
Subtotal 12,190,455 461 ,303 32,747 406 679.977 021 893
Washington:
Property 4,450,530 510,355 460,905
Unemployment 128,203 128 203
Business Occupation 069 369 330
Public Utility 209,715 553,174 961 014
Use 16,219 179,937 188 043
Retailing 834 863
Regulatory Commission 164 718 378 079 361 865-
Franchise 333 175,851 208,184
Subtotal 874 584 942 134 327 681 180 932
Washington D.
Unemployment 486 486
Franchise
Subtotal 486 486
Wyoming:
TOTAL 718,526 10,436,368 151 615.364 202 672,678 661 333
FERC FORM NO.1 (ED. 12-96)Page 262.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
TAXES ACCF UED, PREPAID AND CHARGED DU ING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department-or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items Adjustments to Ret.Other No.ACcOl~nt 236)(Incl. in Account 165)(Account 408.1, 409.(Account 409.Earnings (Account 439)
(h)(i)(k)(I)
11,449,169 743,748 26,563,897 495 589
379
324 779 28,248,848
210,163 975 597
29,276
235 325
483
724
047,483 230 289
818,474 26,548,299 199 108
3,499,980 429 526
892 28,369
801,875 553 174
113
834
175 851
308 105 175 086 767 048
486
604,016 49,692,288 125,762 146 25,853,242
FERC FORM NO.1 (ED. 12-96)Page 263.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
TAXES ACCRUED, PREPAID AND CHAI GED DURING YEAR
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
Line Kind of Tax BALANCE AT BEGINNING OF YEAR ~h~xes
~;~
Adjust-C argedNo.(See instruction 5)1axes Accrued fJrepai.d Taxes ~rlng ~ring ments(Account 236)(Include In Account 165)ear ear
(a)(b)(c)(d)(e)(f)
Property 148 494 843,191 507 109
Property - Glenrock 114,476 123
Unemployment 71,256 256
Interwest Mining Unemploy.138 138
Glenrock Black Lung Tax 113,801
Glenrock Production 244,354 130,553
Glenrock Sales & Use 165,260 168,652
...~..
Franchise 158,470 104 043 108,513
Use 746 211 596 244 857
Annual Report 381 381
Subtotal 589,064 296 987 255 462 70,554
Miscellaneous:
Goshute Possessory 14,309 303
Sho-Ban Possessory 150 132 562 132 712
Navajo Possessory 124 30,816 30,532
Ute Possessory 667 667
Crow Possessory 36,368 871 180
Umatilla 236 236
Misc. Sales & Use Tax Provo 742,019
Provision for Misc. Taxes 123
Subtotal 25,172 -443,564 303 327 013 142
TOTAL 37,718,526 436,368 151 615 364 202 672 678 661,333
FERC FORM NO.1 (ED. 12-96)Page 262.
Name of Respondent This
wort
Is:Date of Report Yea~Penod m Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
TAXES ACCF UED, PREPAID AND CHARGED DU~ING YEAR (Continued)
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (I) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.
pertaining to electric operations. Report in column (I) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (I) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued Prepaid Taxes Electric Extraordinary Items AdjUstments to ReI.Other No.
Acco~nt 236)(Incl. in Account 165)(Account 408.1, 409.(Account 409.Earnings (Account 439)
(h)(i)(k)(I)
3,484 576 827 275
238
844
154 000 104,043
485
381
701 143 962,699 1 ,334 288
21,612 303
132,562
15,408 30,816
667
24,059 59,871
60,236
180 000 742,019
241 ,079 443,564
604 016 692 288 125 762 146 25,853,242
FERC FORM NO.1 (ED. 12-96)Page 263.
Name of Respondent This Report Is:Date of Report Year/Period of Report
PacifiCorp (1) ~ An Original (Mo, Da, Yr)End of 2004/04(2) A Resubmission 04/25/2005
ACCUMULA ED DEFERRED INVESTMENT TAX REDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and
non utility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).lnclude in column (i)
the average period over which the tax credits are amortized.
Line Account Balance at Beginning Deferred for Year AI!OCa110ns to
No.subd
l~~Sions
of Year Current Year's Income Adjustments(c) (d) (e) (f)
1 Electric Utility
23%
510%817 067 411.4/420 413,
7 Idaho 105,073 411.43E
8 TOTAL 922,140 7,479,31~
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
10%526,160 420 440 808
Total Nonutility 526,160 440,808
FERC FORM NO.1 (ED. 12-89)Page 266
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
ACCUMULATED D ~FERRED INVESTMENT TAX CRED TS (Account 255) (continued)
Balance at End AveraRe perloa ADJUSTMENT EXPLANATION Line
of Year of AI ocation No.to Income
73,403,191 30/35
039,637
442,828
085 352
085,352
FERC FORM NO.1 (ED. 12-89)Page 267
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
0 HER DEFFERED CREDITS (Account 253)
1. Report below the particulars (details) called for concerning C?ther deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $10,000, whichever is greater) may be grouped by classes.
Line Description and Other Balance at DEBITS Balance at
No.Deferred Credits Beginning of Year Contra Amount Credits End of Year
Account
(a)(b)(c)(d)(e)(f)
Cogeneration Bonds - Sunnyside 413,417 413,417
Working Capital Deposit DG& 201 000 143 041 312 159,688
Working Capital and Coal Pile
Deposits from Provo City 273,000 273,000
Working capital deposit from UAMPS 278,000 143 249,000 029 000
Reclamation Costs - Trapper Mine 811 150 382 599 193 749
Reclamation Costs - Deseret Mine 770,461 151 19,636 750,825
Reclamation Costs - Trail
Mountain Mine 146,738 146 738
Deferred Compensation - PPL 844 471 131 1 ,555,498 288,973
401 (k) Plan administrative costs 139,565 920 139,565
Pension administrative costs 146,643 146 643
Transmission Service Deposit 254 073 131 364 747 889 326
Deferred Excise Tax 315,099 426.315,099
Def. Credits - Pricing Dispute 298 517 393,614 904 903
MCI F.G. wire lease 559,278 454 380 558 898
Firth Cogeneration Buyout 698 160 131 349,080 349,080
Redding Contract 600 052 456 549,996 050 056
Foote Creek Contract 531,142 137 640 393,502
Lakeview Buyout 110,000 131 000 000
Environmental Liabilities -
Centralia Plant 918,605 426.802 454 116,151
Environmental Liabilities -
Centralia Mine 273 677 431 159,554 114,123
Stock Incentive Plan - 2000 102 888 123 102,888
TOTAL 59,731 246 18,694 715 582,297 58,618,828
FERC FORM NO.1 (ED. 12-94)Page 269
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission . 04/25/2005
0 HER DEFFERED CREDITS (Account 253)
1. Report below the particulars (details) called for concerning I?ther deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $10,000, whichever is greater) may be grouped by classes.
Line Description and Other Balance at DEBITS Balance at
No.Deferred Credits Beginning of Year Contra Amount Credits End of Year
(b)Account(a)(c)(d)(e)(f)
Stock Incentive Plan - 2001 53,971 53,971
Stock Incentive Plan - 2002 130 915 123 783 125,132
Wyoming Joint Powers Water
Board Settlement 875,000 131 300 000 575 000
Comp Reduct 821 316 690 822 512,138
Weather Derivative Liability
Non-Current 693 685 693 685
Unearned Joint Use Pole Contract 922,506 921 158 843,664
Oregon DSM Loans NPV Unearned 841 203 456.459,784 381 419
Exec Trust Comp Reduction Plan -
SPI Stock 053 523 053 523
Miscellaneous Security Deposits 600 600
Environmental Liabilities -
Non-Current 386 952 386,952
TOTAL 731 246 18,694 715 582,297 618,828
FERC FORM NO.1 (ED. 12-94)Page 269.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
This ~rt Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPER (Account 281)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to amortizable
property.
2. For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line
No.
Account Balance at
Beginning of Year
(a)
1 Accelerated Amortization (Account 281)
2 Electric
(b)
Amounts Debited
to Account 410.
(c)
Amounts Credited
to Account 411.
(d)
3 Defense Facilities
4 Pollution Control Facilities
392 714 423,937
5 Other (provide details in footnote):
8 TOTAL Electric (Enter Total of lines 3 thru 7)
9 Gas
10 Defense Facilities
392 714 423,937
11 Pollution Control Facilities
12 Other (provide details in footnote):
15 TOTAL Gas (Enter Total of lines 10 thru 14)
17 TOTAL (Acct 281) (Total of 8,15 and 16)
18 Classification of TOTAL
19 Federal Income Tax
392 714 423,937
392,714 373,222
71520 State Income Tax
21 Local Income Tax
NOTES
FERC FORM NO.1 (ED. 12-96)Page 272
This ~ort Is: Date of Report Year/Period of Report(1) ~ An Original (Mo, Da, Yr) End of 2004/04(2) A Resubmission 04/25/2005
ACCUMULATED DEFERRED INCO E TAXES ACCELERATED AMORT ZATION PROPERTY (Account 281) (Continued)
3. Use footnotes as required.
Name of Respondent
PacifiCorp
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
(h)
Credits
Account
Debited
(i)
Amount
(j)
Balance at
End of Year
Line
No.Debits
(e)(f)
Account
Credited
(g)
Amount
(k)
968,777
968 777
968,777
281 166,611
281 166,611
852,881
115,896
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 273
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
ACCUMULATE DEFFERED INCOME TAXES - OT ER PROPERTY (Account 282)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes rating to property not
subject to accelerated amortization
2. For other (Specify),include deferrals relating to other income and deductions.
CHANGES DURING YEAR
Line
No.
Account Balance at
Beginning of Year
(a)(b)
Amounts Debited
to Account 410.
(c)
Amounts Credited
to Account 411.
(d)
1 Account 282
2 Electric 117 596,494 352,705 051
3 Gas
4 FAS 109 499,036 366
616 632,860
848,913
352,705 0515 TOTAL (Enter Total of lines 2 thru 4)
6 Nonutility
9 TOTAL Account 282 (Enter Total of lines 5 thru
10 Classification of TOTAL
626,481 773 352 705 051
11 Federal Income Tax
12 State Income Tax
626,481 773 310,511 672
42,193 379
13 Local Income Tax
NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
This f3!port Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
ACCUMULATED DEFERRED INCO E TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
(h)
Credits
Account
Debited
(i)
Amount
Balance at
End of Year
Line
No.Debits
(f)
AccountCredited
(g)
Amount
(e)(k)
182.35,068,70 190
35,068,
130
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 275
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
1. Report the information called for below concerning the respondent's accounting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include deferrals relating to other income and deductions.
Year/Period of Report
End of 2004/04
(a)
Balance at
Beginning of Year
(b)
Line
No.
Account
1 Account 283
2 Electric
330,480 624,707,980
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
17 TOTAL Gas (Total of lines 11 thru 16)
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)
20 Classification of TOTAL
21 Federal Income Tax
330 480 320,744 316 624 707 980
330,480 280,306 001 550 000 792
40,438,314 707,18822 State Income Tax
23 Local Income Tax
NOTES
FERC FORM NO.1 (ED. 12-96)Paae 276
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
This ~rt Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
ACCUMULATED EFERRED INCOME TAXES - OTHE (Account 283) (Continued
3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
ADJUSTMENTS
Balance at
End of Year
(k)
Line
No.
448,856
968
623,780,967
77,312,027
360,308,673
360,308,673
317,204 552
43,104 121
509,824
509,824
283 190 701,092,993
701 092 993
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 277
Name of Respondent This &rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) rlA Resubmission 04/25/2005
0 HER REGULATORY LIABILITIES (Account 254)
1. Report below the particulars (details) called for conc~rning other regulatory liabilities, including rate order docket number, if
applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $50,000 which ever is less),may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Balance at Begining DEBITS Balance at End
line Description and Purpose of of Current of Current
No.Other Regulatory Liabilities OuarterNear Account Amount Credits OuarterN earCredited
(a)(b)(c)(d)(e)(f)
FAS 109 Regulatory Liability 019 840 160,610 859,230
Centralia Gain Giveback 773,529 199,558 573,971
Merger Credits 727217 727,217
OR Share Hermiston Gain Credit 172,960)456 172,960)
OR Gain on Sale of Assets to EPUD 191 240~074 385 116,855
Property Insurance Reserve 066,397 957 641 024,038
OR UE134 Power Cost 885,080 885,080
SMUD Revenue Imputation 33,627 580 205,576 848,523 35,270,527
Oregon Rate Refund 786 131 037 251
BPA Washington Balancing Account 119 842 194,868 135,997 060,971
BPA Oregon Balancing Account 363,585 675,397 571 536 10,259,724
,"--
ARO/Reg Diff - Deer Creek Mine Reclamation 139,181 195,423 334,604
ARO/Reg Diff . Trojan Nuclear Plant 782,497 248,873 031,370
FAS 109. WA Flow Through 13,515,318 13,515,318
Reg Liability. OR Balance Consolidation 560,027 560 027
TOTAL 142 523,028 43,111 437 29,164 375 128,575 966
FERC FORM NO. 1/3.0 (REV 02-04)PaQe 278
Blank Page
(Next Page is: 300)
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
E ECTRIC OPERATING REVENUES (Account 400)
1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH
related to unbilled revenues need not be reported separately as required in the annual version of these pages.
2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added
for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of
each month.
4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.
Operating Revenues Year
to Date Quarterly/Annual
(b)
Operating Revenues
Previous year (no Quarterly)
(c)
Line
No.
Title of Account
1 Sales of Electricity
(440) Residential Sales
(442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)
5 Large (or Ind.) (See Instr. 4)
(444) Public Street and Highway Lighting
(445) Other Sales to Public Authorities
(446) Sales to Railroads and Railways
(448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers
812,631 284 782 567 460
748,767,664 709,853,228
16,037 366 16,053,934
703,361 011 098
139 478
502,422 975 409,002 223
011,298,485
830 392 694 3,420 300,708
830 392 694 420 300,684
323,072 978,539
691 582 604 626
170,132
16,712 132 102 862
130,295,327 84,729,753
11 (447) Sales for Resale
12 TOTAL Sales of Electricity
13 (Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Provo for Refunds
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues
18 (453) Sales of Water and Water Power
19 (454) Rent from Electric Property
20 (455) Interdepartmental Rents
21 (456) Other Electric Revenues
26 TOTAL Other Operating Revenues
27 TOTAL Electric Operating Revenues
159,192,245
)~~~.
113,415,780
533,716 464
FERC FORM NO.1 (ED. 12-96)Page 300
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
E ECTRIC OPERATING REVENUES (Account 400)
5. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the
respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification
in a footnote.
6. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.
7. For Lines 2,4,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.
8. Include unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)(d) (e)
AVG.NO. CUSTOMERS PER MONTH
Current Year (no Ouarteny) Previous Year (no Ouarterly)(f)
(g)
475 929
19,454 708
160,911
537,007
323,846
19,262,175
150,496
491,970
190,812
34,485
368
186,943
547
398
48,816,147
13,356,980
173,127
.11
338,551
676,609
73,015,160
578 247 1 ,548,234
108
578,247 548,342
578 247 1 ,548,342173,127 015 160
Line 12, column (b) includes $
Line 12, column (d) includes
900 993
88,582
of unbilled revenues.
MWH relating to unbilled revenues
FERC FORM NO.1 (ED. 12-96)Page 301
Line
No.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1 ) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries In column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
I LIne l\Jumoer ana Iitle Of Rate scneClule Mvvn ~ola Hevenue Average Numoer IS.vvn OT ~ales ~~R~olderNo.(a)(b)(c)of cu
fct\omers
Per 9if)stomer
(f)
1 Residential Sales
2 CA-PPL
3 06BLSKY01 R - BLUESKY ENERGY 168 314
4 06CHCKOOOR-CA RES CHECK M
5 06LNXO01 09-REF/NREF ADV +
6 06NETMT135 - CA RES NET 536 000 0889
060AL T015R-OUTD AR LGT SR 402 70,325 432 931 1749
8 06RESDOOOD-RES SRVC 308 190 26,457 144 28,591 779 0858
9 06RESDDC7 A-CA RES CLEAN A 597 091 240 907 898 0850
06RESDDL06-CA LOW INCOME 46,621 155,825 244 985 0677
06RESDDM9M-MUL TI FAMILY 438 35,531 29,200 0811
06RESDDS8M-MUL T FAM SBMET 284 98,085 85,600 0764
SMUD REVENUE IMPUTATIONS 257
UNBILLED REVENUE 442 275,000 1126
ID-UPL
07ACTSETUP -ID New account
07BLSKY01 R-BLUESKY ENERGY 10,503 330
07LNXOO01 O-MNTHL Y 80%GUAR 800
07LNXOO035-ADV 80%MO GUAR 803
07LNXO0107-SUBDIV ADV+AIC 094
070ALCOO07-CUST OWN LIGHT 198 10,000 2198
070AL TO07R-SECURITY AR LG 307 800 2692
070ALT07AR-SECURITY AR LG 111 25,636 142 782 2310
070ALT07AR-SECURITY AR LG 650
07RESDOO01-RES SRVC 314 383 25,253,648 571 365 0803
07RESDOO01-RES SRVC 607 359
07RESDO036-RES SRVC-OPTIO 295 349 19,202,490 16,176 18,258 0650
07RESDO036-RES SRVC-OPTIO 164 852
07ZZMERGCR-MERGER CREDITS
BPA BALANCING ACCOUNT 129 433
UNBILLED REVENUE 301 69,000 0530
OR-PPL
01ACTSETUP-NEW SRVC SETUP
01 CHCKOOOR-RES CHECK MTR
01 COSTOO04 - 01 RESDOO04 065,220 152,029,544 0300
01 FXRENEWR - Fixed Renewable 180 776 162
01 HABITO04 - 01 RESDOO04 128 611 925 0290
01LNXO0102-LlNE EXT 80% G 869
01 LNXO01 05-CNTRCT $ MIN G
01LNXO0109-REF/NREF ADV +23,183
TOTAL Billed 48,727 564 643,240,940 0542
Total Unbilled Rev.(See Instr. 6)58~900 993 111 a
TOTAL 48,816 14€653 141 933 0543
FERC FORM NO.1 (ED. 12-95)Page 304
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues " Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
LIne NumDer ana Ime OJ Hale scneaUie Mvvn ~old ~evenue Average NumDer ~vvn- OJ ~ales ~WR~olderNo.(a)(b)(c)of c~~)omers Per 9~stomer (f)
1 01NETMT135-NET METERING 180 101 13.7267
01 NETMT135-NET METERING 029
010ALT014R-OUTD AR LGT RE 755 412 815 293 140 1099
4 010ALT014R-OUTD AR LGT RE 605
5 010AL T015R-OUTD AR LGT RE 857 222 4285
01 PTOUOO04 - 01 RESDOO04 388 478,867 0750
01 RENEWO04 - 01 RESDOO04 87,452 506,637 0287
8 01 RESDOO04-RES SRVC 242,152,216 441,818 363.2252
9 01 RESDOO04-RES SRVC 54,338,492
01 RESDO013-3 PHASE RES SR 231 18,223 0789
01 RESDO013-3 PHASE RES SR 051
01RESDO04T - RES Time Option 738,767 980
01 RESDO04T - RES Time Option 151 507
01RESD013X-3 PHASE RES10K 999 0740
01RESD013X-3 PHASE RES10K 112
01 SEAFLX04 - 01 RESDOO04 785 243 0347
01 UPPLOOOR-BASE SCH FALL
01ZZMERGCR-MERGER CREDITS 139,898
BPA BALANCING ACCOUNT 293 430
MERGR CREDIT AMORT-OR(JV)139,865
OR ENRGY COST RECOV AMORT 265,865
SMUD REVENUE IMPUTATIONS 190,381
UNBILLED REVENUE 322 129,000 0620
UT-UPL
08ACTSETUP-NEW SRVC SETUP
08BLSKY01 R-BLUESKY ENERGY 446 380 10,249
08CFROOO01-MTH FACILITY S 630
08CHCKOOOR-UT RES CHECK M
08COOLKPRR - Utah Cool Keeper 959
08LNXOOO01-MTHL Y 80% GUAR
08LNXOOO05-MTHL Y MIN GUAR 240
08LNXOO013-80% MNTHL Y MIN 967
08LNXOO016 - 80% annual 552
08LNXO0101-AGR MTH+ADV+BT
08LNXO0103-LlNE EXT CNTRC 182
08LNXO0107-SUBD ADV & AIC 433
08LNXO0108-ANN COST MTHL Y 005
08MHTPO025-MOBILE HOME &10,821 610 460 983,727 0564
08NETMT135 - Net Metering 252 429 0721
080AL TO07R-SECURITY AR LG 494 665,970 675 951 1906
TOTAL Billed 48,727 564 643 240 940 0542
Total Unbilled Rev.(See Instr. 6)582 900 993 111 S
TOTAL 48,816,14a 653 141 933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo. Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line NumDer ana I !tie Of HaTe scneaUie Mwn ::soia Hevenue Average NumDer ISwn. Of ::sales ~~R~older
No.(a)(b)(c)of Cu(~~omers Per 9~stomer (f)
1 08PTLDOOOR-POST TOP LIGHT 226 16,942 275 0750
2 08RESDOO01-RES SRVC 351 256 375,740 619 615,698 691 0702
08RESDOO02-RES SRVC-OPTIO 783 84,524 176 449 1079
08RESDOO03-LlFELINE PRGRM 130,887 987 963 500 479 0687
5 08RESD0150-RES ALL E NOT5
08RFND1999-UT AH RATE RFND
7 08ZZMERGCR-MERGER CREDITS
8 SMUD REVENUE IMPUTATIONS 185,114
9 UNBILLED REVENUE 32,778 396,000 1036
W A-PPL
02ACTSETUP-NEW SRVC SETUP
02BLSKY01 R-BLUESKY ENERGY 41,811 002
02LNXO0109-REF/NREF ADV +368
020ALT013R.WA OUTD AR LGT 331 143 347 335 997 1077
020ALT013R-WA OUTD AR LGT 13,902
020ALT015R-WA OUTD AR LGT 204 000 1020
02RESDO016-W A RES SRVC 505 460 87,479 318 96,918 15,533 0581
02RESDO016-W A RES SRVC -16 937 128
02RESDOO17-BILL ASSISTANC 950 735,494 882 15,914 0579
02RESDO017-BILL ASSISTANCE 336,926
02RESDO018-W A 3 PHASE RES 718 171 774 103 26,388 0632
02RESDO018-W A 3 PHASE RES 30,580
02RESD018X-WA 3 PHASE RES 732 45,590 26,143 0623
02RESD018X-W A 3 PHASE RES -8,240
02RFNDCENT . CENTRALIA RFND 342,347
02ZZMERGCR-MERGER CREDITS 105,345
BPA BALANCING ACCOUNT 288 004
MERGR CREDIT AMORT-WA(JV)099,452
UNBILLED REVENUE 140 247 000 0787
WY -PPL
05ACTSETUP-NEW SRVC SETUP
05BLSKY01 R-BLUESKY ENERGY 50,584 242
050AL T015R-OUTD AR LGT SR 323 140,240 26€043 1060
05RESDOO02-WY RES SRVC 681,408 036 749 072 105 0690
05RESDOO03-WY OPTIONAL RE 108,850 475,455 120 260 0595
05RESDO018-RES 3 PHASE SR 280 18,479 25,455 0660
05RESD0135 - Experimental Partial 088 500 0696
05RESD018X-RES 3 PHASE SR 106 000 0709
05RFNDCENT-CENTRALIA RFND
09BLSKY01 R-BLUESKY ENERGY
TOTAL Billed 48,727 564 643,240,940 0542
Total Unbilled Rev.(See Instr. 6)88,582 900,993 1118
TOTAL 48,816,146 653,141 933 054:3
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Oa, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE St.HEOULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified In more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
I Line Number ana Il1Ie or Hale scneaule Mwn ~ola Revenue Average Number ISwn ot ~ales ~B~orcf
No.of cus
Oomers
Per 9~stomer
(a)(b)(c)(f)
1 09LNXO0108-ANN COST MTHL Y 119
2 09RESD0201-RES SRVC 146 861 588 0744
3 SMUD REVENUE IMPUTATIONS 386
UNBILLEO REVENUE 171 480,000 1514
5 WY-UPL
05BLSKY01 R-BLUESKY ENERGY 341 138
05RESDOO02-WY RES SRVC 470 084 545 0683
05RESDOO03-WY OPTIONAL RE 011 750 0604
05RESDO018-RES 3 PHASE SR 477 000 0795
05UPPLOOOR-BASE SCH FALL
09BLSKY01 R-BLUESKY ENERGY
09INYCHGOR-INYEST MNT CHG
1::090AL T207R-SECURITY AR LG 999 106 925 2857
09RESD0201-RES SRYC 68,389 201 645 013 588 0~0761
09RESD0205-RES SRVC ALL E 40,383 686,859 238 18,044 0665
09RFNDCENT-CENTRALIA RFND
SMUD REVENUE IMPUTATIONS 827
UNBILLED REYENUE 466 117,002 0798
Less Multiple Billings 508
Total Residential Sales - 440 187 590 905,283,161 348,555 10,521 0638
Commercial Sales
CA-PPL
06BLSKY01 N - BLUESKY ENERGY 13~
06CHCKOOON-CA NRES CHECK
06GNSYO025-CA GEN SRYC 207 776 447 642 366 1089
06GNSY025F-GEN SRVC-c:: 20 872 110,173 689 1263
06GNSVOA32-GEN SRYC-20 KW 70,003 255,044 831 239 0894
06GNSYA32M-GEN SRYC-20 KW
06LGSY048T-LRG GEN SERV 054 718,199 587 833 0555
06LGSYOA36-LRG GEN SRYC-83,458 691,019 202 413 158 0682
06LNXO0102-LlNE EXT 80% G 766
06LNXO0105-CNTRCT $ MIN G 611
06LNXO0109-REF/NREF AOY +111 656
060AL T015N-OUTD AR LGT SR 773 135 886 564 371 1758
06RCFLO042-AIRWAY & ATHLE 282 35,514 231 1259
06WHSYO031-COMM WTR HEATI 298 286 514 0882
SMUD REYENUE IMPUTATIONS 033
UNBILLED REVENUE 152 273,000 0866
TOTAL Billed 727 564 643,240,940 0542
Total Unbilled Rev.(See Instr. 6)88,582 900,993 1118
TOTAL 48,816,146 653,141,933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
--~...
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SC HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
rUne NumDer ana Title or Kate scneoUie Mwn ::soia Hevenue Average NumDer ~wn Of ~ales ~~R~older
No.(a)(b)(c)of C~~\omers Per '(~stomer (f)
1 ID-UPL
2 07BLSKY01 N-BLUESKY ENERGY 893
07CISHO019-COMM & IND SPA 10,315 700,162 314 850 0679
4 07GNSYOO06-GEN SRYC-LRG P 145 745 817 821 882 165 244 0605
5 07GNSYOO09-GEN SRYC-HI YO 502 322,673 32,502,000 0407
6 07GNSYO023-GEN SRYC-SML P 377 227 41€962 18,415 0791
7 07GNSYO035-GEN SRVCOPTION 635 58~817,500 0517
8 07GNSYO06A-GEN SRVC-LRG P 656 434 360 196 115 592 0633
9 07GNSYO06A-GEN SRYC-LRG P -547 468
07GNSVO06M-GNSV LRG POWER 47,704 054 830 23,852 000 0431
07GNSY023A-GEN SRVC-SML P 13,815 138,058 063 996 0824
07GNSY023A-GEN SRYC-SML P 334 955
07GNSY023F-GEN SRVC SML P 420 571 1344
07LNXOO010-MNTHL Y 80%GUAR 380
07LNXOO035-ADY 80%MO GUAR 146,052
07LNXOO040-ADY +REFCHG+80%68€
07LNXO0111-80%MIN+ADY+BTW 239
07LNXO0112-80%ANN+ADY+BTW
070AL TO07N-SECURITY AR LG 256 289 201 274 2121
070ALT07AN-SECURITY AR LG 099 643 2332
070ALT07AN-SECURITY AR LG 213
07ZZMERGCR-MERGER CREDITS
BPA BALANCING ACCOUNT 365 415
UNBILLED REYENUE 160 178,000 0563
OR-PPL
01 BLSKY01 N-BLUESKY ENERGY 79,957
01 BULKBSKY - BULK BLUESKY 113
01COSTO023, OR GEN SRY, COST 912 026 624 583 0380
01COSTO048 - 01LGSVO048 746,104 567 315 0302
01COST023F - OR GEN SRY -264 132 241 0405
01COSTB023 - OR GEN SRV 612 610,264 0394
01COSTB028, OR GEN SRV, COST 859 105 852 0335
01COSTL028, OR LRG SRV, COST 711 ,172 863 280 0336
01COSTL030 - OR LRG GEN SRY 914 789 444 916 0333
01COSTS028, OR GEN SERV 063,407 36,092 486 0339
01COSTS030 - OR GEN SRV CBS,.101 147 372,247 0333
01 FXRENEWN - Fixed Renewable 883 129
01 GNSBO023 - BPA DISC, .;: 30 kW 944 883
01GNSBO023, OR GEN SAY, BPA 139,932 701 379.9773
01GNSBO028 - OR GEN SRYC,714 989
TOTAL Billed 48,727 564 643 240,940 0542
Total Unbilled Rev.(See Instr. 6)88,58~900 993 111S
TOTAL 48,816,14€653 141 933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04
(2) 0 A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SC HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line NumDer ana Title or Hate scneauTe Mvvn ::iOla Hevenue Average Numoer I\.vvn ot ~ales ~~n~older
No.(a)(b)(c)of C~~)omers Per 1~stomer
(f)
1 01GNSBO028, OR GEN SRV, BPA 130,991 465 133.1869
2 01 GNSBO030 - OR GEN SRV, ;:0. 200 60,981
3 01GNSBO030 - OR GEN SRV,;:o.108,793
4 01 GNSB023T - OR GEN SRV - TOU 107 110
5 01 GNSB023T - OR GEN SRVC,15,311
6 01GNSVO023, OR GEN SRV, oe:: 686 29,762,167 50,086 43.3851
7 01 GNSVO028, OR GEN SRV ;:0. 30,088 960 784
01GNSVO030 - OR GEN SRV ;:o. 200 512,104 100
9 01 GNSV023F - OR GEN SRV .485 015,431 954 13,087 0813
01GNSV023M - OR GEN SRV 257 24,000 0940
01GNSV023T, OR GEN SRV, TOU 157 869 261
01HABTO023, OR HABITAT 422 940 0386
01HABTB023 - OR HABITAT 119 843 0407
01 LGSBO028 - OR LRG GEN SRVC 663,810
01LGSBO028, OR LRG GEN SRV,173 440 631 125 384 3273
01 LG SBO030 , GEN DEL SRV ;:o. 200 416,040
01LGSBO030, GEN DEL SRV ;:o. 200 758 967
01 LGSVO028, OR LRG GEN SRV oe::458 16,441 451 582 290 35.8984
01LGSVO030 - OR LRG GEN SRV 16,267 981 506
01LGSVO048-1000KW AND OVR 009 10,149,818 704 3732
01 LGSVO48M-LRG GEN SRVC 1 46,303 620 039 23,151,500 0350
01 LGSVO48T-LRG GEN SRVC T 129 137 117 0438
01LNXO0100-LlNE EXT 60% G 013
01LNXO0102-LlNE EXT 80% G 282,365
01LNXO0103-LlNE EXT 80% G 707
01LNXO0105-CNTRCT $ MIN G 235
01 LNXO01 09-REF/NREF ADV +012,608
01 LNXO011 O-REF/NREF ADV +313
01LNXO0114-TEMP SVC 12MO;:o.
01LNXO0120 - Line Extension 60% G
01 LNXO0300 - LINE EXT 80%232
01 LNXO0311 - LINE EXT 80% G 693
01 LPRS047M-PART REO SRVC 118 911,026 059,000 0900
01NMT23135 - OR NET MTR, GEN,102
010ALT014N-OUTD AR LGT NR 254 255,335 297 738 1133
010AL T014N-OUTD AR LGT NR 18,392
010ALT015N-OUTD AR LGT NR 285 813,030 334 485 0981
01 PRSVL36M, OR PRT REO SRV,;:o.142 282 794 571 000 0900
01 PRSVM36M - OR PRT SRV, 31 -607 25,715 202,333 0424
01PTOUO023, OR GEN SRV, TOU 612 168,834 1047
TOTAL Billed 48,727,56A 643,240,940 054~
Total Unbilled Rev.(See Instr. 6)88,58~900 993 11H
TOTAL 48,816,14E 653,141 933 0542
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SC HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line Numcer ana Ime or Hate scneaule MW n ::iola Hevenue Average ~umcer ISwn- or ::iales ~~~~orcr
No.(a)(b)(c)of C~~)omers Per 9~stomer
(f)
1 01 PTOUB023, OR GEN SRV, TOU 531 55,337 1042
2 01 RCFLO054-REC FIELD LGT 848 75,431 653 0890
3 01 RENWO023, OR RENW USAGE 249 125 545 0386
4 01 RENWB023 - OR RENEWABLE 319 876 0404
5 01 SEAFO023, OR SEAS FLUX 138 593 0405
6 01 SEAFB023 - OR SEASONAL 159 0398
7 01 STDA Y023 - OR DAY STD OFR 193 611 2260
8 01STDAY028 - OR DAY STD OFF,572 155,254 2714
9 01STDAY030 - OR STD DAY OFF 681 186,833 2744
01 XTRNBSKY - Blue Sky 840
01 ZZMERGCR-MERGER CREDITS 758 498
BPA BALANCING ACCOUNT 234 207
MERGR CREDIT AMORT-OR(JV)757,826
OR ENRGY COST RECOV AMORT 15,582,400
SMUD REVENUE IMPUTATIONS 173 354
UNBILLED REVENUE 207 284 000 -0.0308
UT-UPL
08BLSKY01 M - BLUE SKY
08BLSKY01 N-BLUESKY ENERGY 123,252 250
08BULKBSKY - BULK BLUESKY 634
08CFROO051-MTH FAC SRVCHG 65,198
08CFROO052-ANN FAC SVCCHG
08CHCKOpON-UT NRES CHECK
08COOLKPRN - AlC DIRECT LOAD 199
08GNSVOqb6-GEN SRVC-DISTR 982,232 267,063,267 10,270 485,125 0536
08GNSVOO09-GEN SRVC-HI VO 180,657 195,335 854,652 0398
08GNSVO023-GEN SRVC-DISTR 034 919 69,426 640 56,246 400 0671
08GNSVO06A-GEN SRVC-ENERG 149,716 10,708,137 386 108,020 0715
08GNSVO06B-GEN SRVC-DEM&6,491 347 194 360,611 0535
08GNSVO06M-MNL DlST VOL TG 68,354 349,964 258 000 0490
08GNSVO09A-GEN SRVC HI VO 13,948 556 904 974 000 0399
08GNSVO09M-MANL HIGH VOLT 15,702 575,259 15,702,000 0366
08GNSV023F-GEN SRVC FIXED 006 147 177 121 16,579 0734
08GNSV023M-GNSV DIST VOLT 226 611 286 0647
08GNSV06AM-MNL ENERGY TOD 863 163,082 863 000 0570
08GNSV06BM-MNL DEMAND TOD 977 189 949 1 ,488 500 0638
08GNSV06MN-GNSV DIST VOLT 17,942 892,254 207 86,676 0497
08GNSV09AM-MAN TOO HIVOL T 588 26,559 588,000 0452
08GNSV09LM-GEN TOD LAGOON 854 326 989 854 000 0416
08LNXOOO02-MTHL Y 80% GUAR 342,732
TOTAL Billed 48,727 56-1 643,240 940 0542
Total Unbilled Rev.(See Instr. 6)88,58~900,993 111 a
TOTAL 48,816,14E 653,141,933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04
(2) 0 A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SC HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line Number ana Iitle or Hate scneaule Mwn ~ola Hevenue Average Number ISwn oT ~ales w.R~o
No.(a)(b)(c)of C~~\omers Per ~~stomer
(f)
1 08LNXOOO04-ANNUAL 80%GUAR 46,960
2 08LNXOOO06-FIXD MTHL Y MIN 891
3 08LNXOOO08-ANNUALMIN GUAR 130
4 08LNXOO014-80% MIN MNTHL Y 939,751
5 08LNXOO017-ADV/REF&80%ANN 986
08LNXO0150-AGR MTH GUAR M 958
08LNXO0151-AGR MTH+ADV+BT 30,622
08LNXO0152-AGR ANN GUAR M 144
08LNXO0153-AGR ANN+ADV+BT 555
08LNXO0158-ANNUALCOST MTH 976
08LNXO0300 - LINE EXT 80% PLUS 182,033
08NMT23135 - UT NET MTR, GEN,172 000 0860
080AL TO07N-SECURITY AR LG 10,406 602 365 032 068 1540
08POLEO075-POLES W/LIGHT 938
08PRSV031 M-BKUP MNT&SUPPL 13,730 752,626 865,000 0548
08PTLDOOON-POST TOP LIGHT 867 125 0749
08SLC1202F-TRAFFIC SIG NM 254 13,731 938 0541
08SLCU1202-TRAF & OTHER S 528 96,431 349 378 0631
08SLCU 1203-MTR OUTDONIGHT 926 630,902 248 004 0707
08XTRNBLUE - BLUESKY ANN 10,247
08ZZMERGCR-MERGER CREDITS 383
SMUD REVENUE IMPUTATIONS 220,799
UNBILLED REVENUE 024 942,000 0672
WA-PPL
02BLSKY01 N-BLUESKY ENERGY 826
02GNSVO024-W A GEN SRVC 463,110 716 882 668 36,557 0598
02GNSVO025-WA GEN SRVC DO 48,360 103,848 27e 753 0642
02GNSVO025-W A GEN SRVC DO 544 031
02GNSV024F-WA GEN SRVC-256 108,339 123 10,211 0863
02GNSV025F-GEN SRVC DOM/F 287 21,313 091 0743
02GNSV025F-GEN SRVC DOM/F 409
02GNSV24FP-GNSV SEASONAL 184 254 123 496 3166
02GNSV24FP-GNSV Seasonal 676
02LGSVO035-WA LRG GEN SRV 514 169,817 789,325 0484
02LGSVO035-WA LRG GEN SRV 736,420
02LGSVO036-WA LRG GEN SRV 613,876 29,579,165 745 823,995 0482
02LGSV048T-LRG GEN SRVC 1 149,039 426,096 139,276 0431
02LNXO0102-LlNE EXT 80% G 43,787
02LNXO0103-LlNE EXT 80% G 124
02LNXO0105-CNTRCT $ MIN G 181
TOTAL Billed 727,564 643,240,940 0542
Total Unbilled Rev.(See Instr. 6)582 900,993 1118
TOTAL 816,146 653 141 933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SC"HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
LIne NumDer ana Ime 01 Hate scneaule MWn t)Old Hevenue Average NumDer ~wn OT ~ales ~&W~o~er
No.(a)(b)(c)of Cus~omers Per 1~stomer
(f)
1 02LNXO0109-REF/NREF ADV +152 938
2 02LNXO0110-REF/NREF ADV +281
3 02LNXO0112-YR INCURRED CH 669
4 02LNXO0300-LlNE EXT 80% G 918
5 020AL T013N-W A OUTD AR LGT 768 023 630 219 1068
6 020ALT013N-WA OUTD AR LGT -8,025
7 020ALT015N-WA OUTD AR LGT 902 188,211 905 102 0990
8 02PRSV033M-PART REO SERV 531 0708
9 02RCFLO054-WA REC FIELD L 336 23,494 500 0699
02RFNDCENT - CENTRALIA RFND 842,063
02SPWHO038-WA SPACE & WTR 156 222 333 0591
02WHCHO042-WA CNTRLD WTR 123 10,078 618 0819
02WHCHO042-W A CNTRLD WTR 385
02WHCH042X-WA CNTRLD WTR 299 203 477 0776
02ZZMERGCR-MERGER CREDITS 859 575
BPA BALANCING ACCOUNT 730
MERGR CREDIT AMORT-WA(JV)841 888
UNBILLED REVENUE 9,495 345,000 0363
WY -PPL
05BLSKY01 N-BLUESKY ENERGY 813
05GNSVO025-WY GEN SRVC 751 901 47,771 194 19,229 39,102 0635
05GNSV025F-GEN SRVC-FL RA 096 115,704 195 621 1056
05GNSV025M - General Service 513 0504
05LGS45025-LRG GEN SRVC 136,386 493,095 158 863,203 0549
05LGSVO045-LRG GEN SRVC 29,775 585 791 160 186,094 0533
05LGSV045M-LRG GEN SRVC 490 16,332 490,000 0333
05LGSV046M-WY LRG GEN SRV 677 44,942 677 000 0;0268
05LGSV046T-LRG GEN SERV 206,599 843,519 10,329,950 0428
05LNXO0100-LlNE EXT 60% G 169
05LNXO0102-LlNE EXT 80% G 151,592
05LNXO01 05-CNTRCT $ MIN G 611
05LNXO01 09-REF/NREF ADV +357 263
05LNXO011 O-REF/NREF ADV +213
05LNXO0114-TEMP SVC 12MO~152
05NMT25135 - WY NET MTR, GEN,132 000 0660
050AL T015N-OUTD AR LGT SR 043 419 623 923 102 1038
05RCFLO054-WY REC FIELD L 639 43,551 11,411 0682
05RFNDCENT-CENTRALIA RFND
09GNSV0206-GEN SRVC-SINGL 246 000 2460
SMUD REVENUE IMPUTATIONS 786
TOTAL Billed 727 564 643 240 940 0542
Total Unbilled Rev.(See Instr. 6)88,582 900,993 1118
TOTAL 48,816,146 653,141 933 054~
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This (!prt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) LJ A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SC HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line NumlJer ana Iltle Of Hate scneoUie Mvvn ~ola Hevenue Average NumDer ISwn of ~ales ~~R~older
No.(a)(b)(c)of C~~\omers Per 9~stomer
(f)
1 UNBILLED REVENUE 22,753 611 000 0708
2 WY -UPL
3 05BLSKY01 N-BLUESKY ENERGY
4 05GNSVO025-WY GEN SRVC 701 273 0826
5 05LNXO0102-LlNE EXT 80% G 20,355
05LNXO0103-LlNE EXT 80% G 597
7 05LNXO0109-REF/NREF ADV +43,675
8 05LNXO0110-REF/NREF ADV +039
9 09GNSV0206-GEN SRVC-SINGL 111,958 652,841 181 333 0594
09GNSV206F-GEN SRVC-FIXED 279 23,302 154 0835
09GNSV206M-GENSERV MANUAL 834 212 208 278,000 0553
09INVCHGON-INVEST MNT CHG
09LGSV0208-LGSV OPTIONAL 126 222,434 375,333 0539
09LGSV208M-LGS OPTNL MANL 520 807 520,000 0578
090AL T207N-SECURITY AR LG 320 353 147 177 2730
09SLCU2123-MTR OUTDONIGHT 378 15,667 0719
SMUD REVENUE IMPUTATIONS 035
UNBILLED REVENUE 844 530,998 0677
Less Multiple Billings 365
Total Commercial Sales - 442.475,929 812,631,284 190,812 75,865 0561
Industrial Sales
CA-PPL
06GNSVO025-CA GEN SRVC 042 114 271 108 648 1097
06GNSVOA32-GEN SRVC-20 KW 391 152,166 66,238 1094
06GNSVA32M-GEN SRVC-20 KW
06LGSV048M - LG GEN SRV TOU 4,460 227 626 460,000 0510
06LGSV048T-LRG GEN SERV 590 628,230 931,667 0552
06LGSVOA36-LRG GEN SRVC-246 753,054 569,222 0735
06LNXO0109-REF/NREF ADV +656
060AL T015N-OUTD AR LGT SR 280 667 1520
SMUD REVENUE IMPUTATIONS 998
UNBILLED REVENUE 770 000 0597
ID-UPL
07CFROOO01-MTH FACILITY S 217
07CISHO019-COMM & IND SPA 199 14,310 28,429 0719
07GNSVOO06-GEN SRVC-LRG P 367 485,408 114 801,465 0491
07GNSVOO08-GEN SRVC-MEDIU 508 133 628 836,000 0533
07GNSVOO09-GEN SRVC-HI VO 75,741 105 659 885,545 0410
TOTAL Billed 48,727,564 643 240 940 0542
Total Unbilled Rev.(See Instr. 6)88,582 900,993 1118
TOTAL 48,816,146 653,141,933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues . Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
LIne NumDer ana Iltle or Hate scneaule Mwn ::)ola Hevenue Average NumDer ISwn- Of :sales ~~RfotderNo.(a)(b)(c)of c~~)omers Per 9~stomer
(f)
1 07GNSVO023-GEN SRVC-SML P 516 725,121 371 650 0762
2 07GNSVO06A-GEN SRVC-LRG P 940 362 466 152 308 0610
3 07GNSVO06A-GEN SRVC-LRG P 143,256
4 07GNSV023A-GEN SRVC-SML P 2,481 221 209 277 957 0892
5 07GNSV023A-GEN SRVC-SML P 909
6 07LNXOO035-ADV 80%MO GUAR 77~
7 07LNXO0108-ANN COST MTHL Y 996
8 070AL TO07N-SECURITY AR LG 1 €804 842 2378
9 070ALT07AN-SECURITY AR LG 345 500 3450
070ALT07AN-SECURITY AR LG -31
07SLCU1201-TRAF SIGNAL SY 423 667 1016
07SPCLOO01 385,500 517,90€385 500 000 0307
07SPCLOO02 115 214 923 830 115,214 000 0341
BPA BALANCING ACCOUNT -58 174
UNBILLED REVENUE 238,000 7.4375
OR-PPL
01 BLSKY01 N-BLUESKY ENERGY 665
01COSTO023, OR GEN SRV, COST 23,176 881 454 0380
01COSTO048 - 01LGSVO048 653,653 566,945 0294
01 COST023F - OR GEN SRV -142 0473
01COSTB023 - OR GEN SRV 294 867 0404
01COSTB028, OR GEN SRV, COST 221 485 0339
01 COSTL028 , OR LRG SRV, COST 66,230 223,425 0336
01 COSTLO3O - OR LRG GEN SRV 287 286 576,916 0333
01COSTS028, OR GEN SERV 097 766 928 0339
01 COSTS030 - OR GEN SRV CBS
;:.
29,013 965,519 0333
01 GNSBO023 - BPA DISC, " 30 kW 049
01GNSBO023, OR GEN SRV, BPA 219
21:01 GNSBO028 - OR GEN SRVC 5,444
01GNSBO028, OR GEN SRV, BPA 19,845
01GNSVO023, OR GEN SRV " 30 805,692 1 ,251
01 GNSVO028, OR GEN SRV ;:. 30 013,371 390
01GNSVO030 - OR GEN SRV ;:' 200 948 719
01 GNSV023F - OR GEN SRV -449
01 GNSV023M - OR GEN SRV 853 000 0597
01GNSV023T, OR GEN SAY, TOU 987
01 GNSV030M - OR GEN SRV, 200 507 000 2535
01 HABTO023, OR HABITAT 659 0386
01 LGSBO028 - OR LRG GEN SRVC 270
01 LGSBO028, OR LRG GEN SRV 269
TOTAL Billed 727 56~643,240,940 054~
Total Unbilled Rev.(See Instr. 6)88,58~900,993 11H
TOTAL 816,14E 653,141,933 054~
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SLHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues " Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line NumDer ana title or Hate scneaUie Mwn ~ola Hevenue Average I"lIumoer ISwn or ~ales ~~R~older
No.(a)(b)(c)of cus
Oomers
Per r~stomer (f)
1 01LGSBO030, GEN DEL SRV, ~ 200 479
2 01LGSBO030, GEN DEL SRV, ~ 200 69,222
01 LGSVO028, OR LRG GEN SRV c::824,017 165
4 01 LGSVO030 - OR LRG GEN SRV 338,285 174
5 01 LGSVO048-1 OOOKW AND OVR 964 730 121
6 01LGSV048M-LRG GEN SRVC 1 613,380 22,314,312 122,676,000 0364
7 01 LNXO01 02-LlNE EXT 80% G 372
8 01LNXO0105-CNTRCT $ MIN G
9 01LNXO0109-REF/NREF ADV +377
01 LNXO0300 - LINE EXT 80%189
01 LPRS047M-PART REO SRVC 188,008 499 350 601 600 0505
010AL T014N-OUTD AR LGT NR 242 222 1129
010ALT014N-OUTD AR LGT NR
010AL T015N-OUTD AR LGT NR 554 845 179 095 0936
01 PRSV036M-SML PART REO S 10,531 1062
01 PRSVL36M, OR PRT REO SRV
, ~
913 000 4547
01PRSVS36M - OR PRT REO SRV 666 000 1332
01PTOUO023, OR GEN SRV, TOU 487 1020
01 RENWO023, OR RENW USAGE 152 748 0378
01RENWB023 - OR RENEWABLE 132 0440
01ZZMERGCR-MERGER CREDITS -359,610
BPA BALANCING ACCOUNT 843
MERGR CREDIT AMORT-OR(JV)359 566
OR ENRGY COST RECOV AMORT 341 372
SMUD REVENUE IMPUTATIONS 111 518
UNBILLED REVENUE 12,605 570,000 0452
UT-UPL
08BLSKY01 N-BLUESKY ENERGY
08CFROO051-MTH FAC SRVCHG 007
08EFOPO021-ELEC FURNACE 0 974 143,277 658 000 0726
08EFOP021 M-ELEC FURNACE 0 303 154 726 651,500 1187
08GNSVOO06-GEN SRVC-DISTR 1 ,585 859 84,081 066 487 1 ,066,482 0530
08GNSVOO09-GEN SRVC-HI VO 197 797 76,300,463 107 20,540,159 0347
08GNSVO023-GEN SRVC-DISTR 59,268 087 286 023 732 0690
08GNSVO06A-GEN SRVC-ENERG 52,952 4,431 946 187 283,166 0837
08GNSVO06B-GEN SRVC-DEM&830 176,420 404 286 0623
08GNSVO06M-MNL DIST VOL TG 456 773 877 645,600 0491
08GNSVO09A-GEN SRVC HI VO 16,445 849,565 740,833 0517
08GNSVO09B-GEN SERVHI VOL 424 247 714 424,000 0334
08GNSVO09M-MANL HIGH VOLT 673,376 829,427 56,114 667 0339
TOTAL Billed 727 56~643,240,940 0542
Total Unbilled Rev.(See Instr. 6)88,58~900,993 1118
TOTAL 48,816,14€653,141 933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
I Line NumDer ana Ime or Hate scneaUie Mwn tjola Hevenue Average-rqLJmcer ~wn OT tjales ~WR~o~er
No.(a)(b)(c)of Cu
fcJ)omers
Per r~stomer (f)
1 08GNSV023F-GEN SRVC FIXED 188 500 2376
08GNSV06MN-GNSV DIST VOLT 911 280 65,071 0519
08GNSV09AM-MAN TOD HIVOL 690 122 638 690 000 0726
4 08LNXOOO02-MTHL Y 80% GUAR 799
08LNXOOO04-ANNUAL 80%GUAR 830
6 08LNXOO014-80% MIN MNTHL Y 25,120
08LNXOO017 -ADV /REF&80%ANN 827
8 08LNXO0150-AGR MTH GUAR M 728
08LNXO0151-AGR MTH+ADV+BT 824
08LNXO0153-AGR ANN+ADV +BT 144
08LNXO0158-ANNUALCOST MTH 100
08LNXO0300 - LINE EXT 80% PLUS 276
080AL TO07N-SECURITY AR LG 858 261 617 585 176 1408
08PRSV031 M-BKUP MNT&SUPPL 688 168 031 688 000 2442
08SLCU1202-TRAF & OTHER S 443 250 0594
08SLCU1203.MTR OUTDONIGHT 882 500 3202
08SPCLOO01 595 612 719,070 595,612 000 0297
08SPCLOO02 691 482 381 ,187 691 ,482 000 0237
08SPCLOO03 688,999 308,874 688,999 000 0353
08SPCLOO05 235 223 647 235 235,223,000 0325
08ZZMERGCR-MERGER CREDITS
SMUD REVENUE IMPUTATIONS 225 233
UNBILLED REVENUE 996 611 000 6135
W A-PPL
02GNSVO024-WA GEN SRVC 573 324 676 394 754 0614
02GNSVO025-WA GEN SRVC DO 312 347 035 138 38,493 0653
02GNSVO025-W A GEN SRVC DO -59,764
02GNSV024F-WA GEN SRVC-015 250 1520
02GNSV24FP-GNSV SEASONAL 969 000 1615
02GNSV24FP-GNSV Seasonal
02LGSVO035-W A LRG GEN SRV 289 139,239 228,900 0608
02LGSVO035-W A LRG GEN SRV 25,747
02LGSVO036-W A LRG GEN SRV 155 955 666,390 142 098 275 0492
02LGSV048M-W A LRG GEN SRV 100 452,340 100,000 0411
02LGSV048T-LRG GEN SRVC 1 758,262 29,524,042 062 833 0389
02LNXO0102-LlNE EXT 80% G 371
02LNXO01 09-REF/NREF ADV +049
020ALT013N-WA OUTD AR LGT 904 636 1084
020ALT013N-WA OUTD AR LGT 385
020AL T015N-W A OUTD AR LGT 166 15,806 320 0952
TOTAL Billed 48,727 564 643,240 940 0542
Total Unbilled Rev.(See Instr. 6)582 900 993 111 a
TOTAL 816,146 653 141 933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) LJ A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SC HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues, II Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line NumDer ana Ime Of Hate scneOUIe MVV n ~ola Hevenue Average NumDer ISwn or ~ales ~W~ lder
No.(a)(b)(c)of Cus~omers Per 9~stomer
(f)
1 02PRSY47TM-LRG PART REOMT 351 525,576 351 000 1568
2 02RFNDCENT - CENTRALIA RFND 152,429
3 02WHCH042X-W A CNTRLD WTR 248 000 0693
02ZZMERGCR-MERGER CREDITS 759,115
5 BPA BALANCING ACCOUNT 169
6 MERGR CREDIT AMORT-WA(JY)470,638
UNBILLED REYENUE 777 -154 000 0227
8 WY -PPL
9 05GNSYO025-WY GEN SRYC 139,149 135,523 650 333 0585
05GNSY025F-GEN SRYC-FL RA 442 500 0959
05GNSY025M - General Service 659 297 086 886 333 0525
05LGS45025-LRG GEN SRYC 88,748 372,704 613,600 0493
05LGSYO045-LRG GEN SRYC 912 841,367 314 246 0470
05LGSY045M-LRG GEN SRYC 802 392,122 267,333 0576
05LGSY046M-WY LRG GEN SRY 672,802 28,217 433 100 250 0419
05LGSY046T-LRG GEN SERV 547 750 60,718,567 23,811 538 0392
05LGSY048M- TOU~ 1 OOOKW MAN 838 156,307 838,000 0323
05LGSV048T-LRG GENSRY TIM 197 604 008,321 171 086 286 0309
05LNXO0100-LlNE EXT 60% G 25,246
05LNXO0102-LlNE EXT 80% G 141 519
05LNXO01 05-CNTRCT $ MIN G 38,300
05LNXO0109-REF/NREF ADV +276 138
050ALT015N-OUTD AR LGT SR 107 10,387 981 0971
05PRSY033M-PART SERY REO 963,307 954 733 192 661 400 0384
05RFNDCENT-CENTRALIA RFND 939
05SPCLOO01-268 117 715 268 000 0568
SMUD REYENUE IMPUTATIONS 268,519
UNBILLED REYENUE 066 340,000 0161
WY-UPL
05LNXO0102-LlNE EXT 80% G 252
05LNXO0109-REF/NREF ADY +23,100
09GNSY0206-GEN SRYC-SINGL 60,928 214,090 399 152 702 0528
09GNSY0217-LRG POWER SRVC 383,016 12,678,082 877 000 0331
09GNSY206M-GENSERY MANUAL 939 180 461 984 750 0458
09GNSY217M-LRG POWER SRVC 272,182 909,965 436,400 0327
09LGSY0208-LGSY OPTIONAL 276 423,934 319,000 0457
090AL T207N-SECURITY AR LG 244 250 2493
09PRSY218M-BKUP MNT SUPPL 199 709 225 374 66,569,667 0362
SMUD REVENUE IMPUTATIONS 50,029
UNBILLED REYENUE 238 282 992 0668
TOTAL Billed 48,727 564 643,240,940 0542
Total Unbilled Rev.(See Instr. 6)88,582 900,993 111S
TOTAL 816 146 653,141,933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE Sc..HEDULES
1. Report below for each rate schedule In effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
LIne Numoer ana Iitle Of Rate scneoUie Mvvn SORt Hevenue Average Numoer IS.vvn OT tiales ~&R~older
No.(a)(b)(c)of cu~\omers Per 9~stomer
(f)
1 Less Multiple Billings 238
3 Total Industrial Sales - 442.18,150 671 697,061 038 815 1 ,536,240 0384
5 Irrigation Sales
CA-PPL
06APSVO020-AG PMP SRVC 584 084 726 310 49,301 0787
06LNXO0103-LlNE EXT 80% G 252
06LNXO0110-REF/NREF ADV +11 ,539
06SLXOOO01-KLAM FALLS MIN 519
06SLXOOO02-KLAM FALLS IRG 652
06UKRBO035-KLAM OFF PROJ
06USBRO040-KLAM IRG ONPRJ 252 163,513 600 45,420 0060
06USBR033T USeR 10,918 40,696 266,293 0037
IRRIGATION UNBILLED 450 000 1133
ID-UPL
07APSA010L - IRG & Pump BPA 774 585
07APSA010L -IRG & Pump Large 19,230 181 566 134 143,507 0614
07APSA010S - IRG & Pump BPA 15,994
07APSA010S -IRG & Pump Small 398 32,833 371 0825
07APSAL10X - IRG & PUMP - Large 268 83,585 60,381 0659
07APSAS10X - IRG & PUMP - Small 517 750 0839
07APSB010L -IRG & Pump BPA 294 097
07APSB010L - IRG & Pump Large 283 475,349 132 174 0653
07APSB010S - IRG & Pump BPA 10,160
07APSB010S - IRG & Pump Large 253 20,531 10,542 0812
07APSBL10X -IRG & PUMP - Large 952 000 0751
07APSBS10X -IRG & PUMP - Sm 124 10,230 500 0825
07APSC010L -IRG PUMP Srv BPA 20,407,077
07 APSC01 OL - IRG PUMP Srv Large 508 391 30,963 583 373 150,724 0609
07APSC010S -IRG PUMP Srv BPA 139 218
07APSC010S -IRG PUMP SRV 3,461 280,788 392 829 0811
07 APSCL 1 OX - was 07 APSC1 OLX 647 1 ,206,168 277 318 0647
07APSCS10X - was 07APSC10SX 668 781 129 178 0940
07 APSVCNLL-LRG LOAD CANAL 675 692 112 395 938 0534
07APSVCNLL-LRG LOAD CANAL 241 756
07 APSVCNLS-SML LOAD CANAL 052 938 0848
07 APSVCNLS-SML LOAD CANAL 118
07BPADEBIT-BPA ADJUST FEE 201 417
07LNXOO015-ANNUAL 80%GUAR 952
TOTAL Billed 48,727,564 643,240,940 0542
Total Unbilled Rev.(See Instr. 6)582 900,993 111 a
TOTAL 48,816,146 653,141,933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) D A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SC HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
LIne NumDer ana Ime OT Hate scneoUie Mwn ~ola Hevenue Average NumDer IS w n- OT ~ales ~~R~older
No.(a)(b)(c)of cu(~)omers Per 1~stomer (f)
1 07LNXOO035-ADV 80%MO GUAR 9.:1
2 07LNXOO040-ADV+REFCHG+80%028
07LNXO0107-SUBD ADV & AIC 097
4 07LNXO0111-80%MIN+ADV+BTW 158
5 07LNXO0112-80%ANN+ADV+BTW 903
6 07MISCOOOO-FEE OFFERING N 711
7 07ZZMERGCR-MERGER CREDITS 140
8 IRRIGATION BPA BAL ACCT 847 252
9 UNBILLED REV -IRRIGATION 141 000 0496
OR-PPL
01 APSVO041-AG PMP SRVC BP 838,132 924
01 APSVO041-AG PMP SRVC BP 456,504
01APSV041L-OR Pumping Serv 264 434 009
1.:1 01 APSV041 L-OR Pumping Serv 645,383
01 APSV041 T - AGR PUMP SRV -5,714
01 APSV041 T - AGR PUMP 25,109
01 APSV041 X-AG PMP SRVC 70,818 222
01APSV41XL-OR Pumping Serv no 152,068
01 BPADEBIT-BPA ADJUST FEE 13,068
01COSTO023, OR GEN SRV, COST 239 0335
01COSTO041 113,669 737 349 0329
01 COSTB023 - OR GEN SRV 0470
01COSTS028, OR GEN SERV 251 491 0338
01GNSVO028, OR GEN SRV:;. 30 615
01HABIT041 - 01 APSVO041 AG 526 0329
01LNXO0102-LlNE EXT 80% G 403
01LNXO0103-LlNE EXT 80% G 11,941
01LNXO0109-REF/NREF ADV +838
01 LNXO011 O-REF/NREF ADV +58,778
01NMT41135 - NETMTR AG PMP 23S
01PTOUO041 - 01 APSVO041 AG 15,68.:1 1686
01RENEW041 - 01 APSVO041 AG 827 0338
01SEAFLX41 - 01 APSVO041 AG
01SLXOOO05-KLAMATH FALLS 187 114
01 SLXOO013-K FALLS IRG MI 831
01SLXOO014-K FALLS IRG MI 371
01 STDA Y041 - Daily Standard Offer 240
01 UKRBO035-KLAMA TH BASIN 106 428,295 680 83,979 0075
01 UKRBO035-KLAMA TH BASIN 274,758
01 USBRO040-KLAMATH BASIN 590 387 535 371 112 0060
TOTAL Billed 727 564 643,240 940 0542
Total Unbilled Rev.(See Instr. 6)88,582 900,993 1118
TOTAL 48,816,146 653,141,933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SC HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues " Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
I Line NumDer ana Iitle or Hate scneaule Mwn ~ola Hevenue Average Numoer ISWn or ~ales ~v.7R ~e rcrNo.(a)(b)(c)of C~~)omers Per 9~stomer
(f)
1 01USBRO040-KLAMATH BASIN -246,326
2 01 USBR33TX-IR TOU W/O BPA 788 376 278 800 0037
01ZZMERGCR-MERGER CREDITS 13,968
IRRIGATION BPA BAL ACCT 262,368
5 IRRIGATION UNBILLED 119 10,000 0840
6 MERGR CREDIT AMORT-OR(JV)910
7 OR ENRGY COST RECOV AMORT 384 853
8 OR Irrigation - BPA adjustment 33,927
9 UT-UPL
08APSVO010-IRR & SOIL ORA 193,428 916,571 340 662 0461
08APSV10NS- Irg Soil Drain Pump N 946 367 147 176,578 0462
08LNXOOO02-MTHL Y 80% GUAR 597
08LNXOOO04-ANNUAL 80%GUAR 36,687
08LNXOO014-80% MIN MNTHL Y 820
08LNXOO017 -ADV /REF&80%ANN 598
08LNXO0151-AGR MTH+ADV+BT 241
08LNXO0152-AGR ANN GUAR M 615
08LNXO0153-AGR ANN+ADV+BT 306
UNBILLED REV -IRRIGATION 000 0714
W A-PPL
02APSVO040-W A AG PMP SRVC 136,799 7,458,825 805 28,470 0545
02APSVO040-W A AG PMP SRVC 538 816
02APSV040X-WA AG PMP SRVC 116 863,889 507 31,787 0536
02BPADEBIT-BPA ADJUST FEE 43,435
02LNXO0102-LlNE EXT 80% G 138
02LNXOO103-LlNE EXT 80% G 031
02LNXO0105-CNTRCT $ MIN G
02LNXO0109-REF/NREF ADV +998
02LNXO011 O-REF/NREF ADV +53,314
02RFNDCENT - CENTRALIA RFND 220 197
02ZZMERGCR-MERGER CREDITS 940
IRRIGATION BPA BAL ACCT 148,935
IRRIGATION UNBILLED 206 23,000 1117
MERGR CREDIT AMORT-WA(JV)829
WY -PPL
05APSOO040-AG PUMPING SVC 678 015 461 523 28,065 0692
05LNXO0109-REF/NREF ADV +
05LNXO0110-REF/NREF ADV +281
IRRIGATION UNBILLED 000 3571
WY-UPL
TOTAL Billed 727 56~643,240,940 054~
Total Unbilled Rev.(See Instr. 6)58~900 993 11H
TOTAL 816,14€653 141 933 054~
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04
(2) Ei A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line NumDer ana Iitle or Hate scneaule Mwn ::soia Hevenue ~verage NumDer ~wn or ::sales ~WR~o~er
No.(a)(b)(c)of Cu(~\omers Per ~~stomer (f)
1 05LNXO0103-LlNE EXT 80% G 718
2 05LNXO011 O-REF/NREF ADV +960
09APSV0210-IRR & SOIL DRA 498 92,013 655 0614
4 Less Multiple Billings 488
6 Total Irrigation Sales - 442.1 ,304 036 706,626 670 523 0397
Public Street & Highway Lighting
9 CA-PPL
06COSLO052-CO-OWND STR LG 658 600 7073
06CUSL053F-SPECIAL GUST 0 531 143,136 126 151 0935
06CUSL058F-CUST OWND STR 252 27,783 10,080 1103
06HPSVO051-HI PRESSURE SO 725 149 033 177 2056
060AL T015N-OUTD AR LGT SR 479 500 2395
UNBILLED REVENUE 000 6667
ID-UPL
07SLCOO011-STR LGT CO-OWN 128 30,864 571 2411
07SLCU1201-TRAF SIGNAL SY 198 146 000 0866
07SLCU 1203-STR LGT GUST -306
07SLCU 122A-STR LGT GUST -177 10,086 13,615 0570
07SLCU 122B-STR LGT CUST -663 188,851 220 559 1136
UNBILLED REVENUE -50 -9,000 1800
OR-PPL
01 COSLO052-STR LGT SRVC C 305 220,231 112 20,580 0955
01 CUSLO053-CUS-OWNED MTRD 649 43,519 14,422 0671
01 CUSL053F-STR LGT SRVC C 10,780 492 645 177 904 0457
01 HPSVO051-HI PRESSURE SO 19,501 656 168 664 29,369 1362
01 MVSLO050-MERC VAPSTR LG 855 305,169 322 46,134 0879
010AL T014N-OUTD AR LGT NR 483 000 1236
01 OAL T014N-OUTD AR LGT NR
010AL T015N-OUTD AR LGT NR 581 250 1054
01ZZMERGCR-MERGER CREDITS 12,912
MERGR CREDIT AMORT-OR(JV)12,912
OR ENRGY COST RECOV AMORT 164 15S
UNBILLED REVENUE 000 0972
UT-UPL
08CFROO012-STR LGTS (CONV
08CFROO051-MTH FAC SRVCHG 529
08CFROOO61-U/G AREA LIGHT 127
08CFROO062-STREET LIGHTS
TOTAL Billed 48,727,564 643,240,940 05~
Total Unbilled Rev.(See Instr. 6)58~900,993 111f
TOTAL 816 14E 653,141 933 054~
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SC HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues " Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
jLine NumDer ana Iitle or Hate scneaUfe Mwn ~ola Hevenue Average NumDer ~wn or ~ales ~~R~e lder
No.of cus~omers Per r~stomer(a)(b)(c)(f)
1 08HAXTO060-LlGHTNG-HAXTON 350 000 3500
2 080AL TO07N-SECURITY AR LG 172 28,078 423 1632
3 08SLC1202F-TRAFFIC giG NM 37:3 891 129 10,643 0509
4 08SLCOO011-STR LGT CO-OWN 25,245 605,754 180 21,394 1824
5 08SLCU1202-TRAF & OTHER S 848 484 322 540 096 0617
08SLCU 1203-MTR OUTDONIGHT 006 71,030 27,189 0706
08SLCU121A-STR LGT CUST-790 008,645 360 083 0682
8 08SLCU121B-STR LGT CUST-19,309 466,589 573 33,698 0760
9 08SLD13ES1-DECOR GUST-OWN 215 139,022 225 469 0193
08SLD13ES2-DECOR GUST -OWN 423 212,927 117 891 0393
08SLD13FS1-DECOR COMP-OWN 19,647 000 6549
08SLD13FS2-DECOR COMP-OWN 195 80,829 19,500 4145
08SLD13MS1-DECOR CUST-OWN 153 14,055 750 0919
08SLD13MS2-DECOR CUST-OWN 604 60,708 20,133 1005
08THIKO077-STR LIGHT SPEC 141 277 141,000 1225
08ZZMERGCR-MERGER CREDITS
UNBILLED REVENUE 739 42,000 0568
W A-PPL
02CFROO012-STR LGTS (CONV 8:3
02COSLO052-W A STR LGT SRV 438 38,132 909 0871
02CUSL053F-W A STR LGT SRV 832 188,979 170 541 0493
02CUSL053M-W A STR LGT SRV 955 52,228 790 0547
02HPSVO051-WA HI PRESSURE 930 405,227 134 21,866 1383
02MVSLO057-WA MERC VAPSTR 356 196 411 36,813 0834
02RFNDCENT - CENTRALIA RFND 25,061
02ZZMERGCR-MERGER CREDITS 600
MERGR CREDIT AMORT-WA(JV)11 ,377
UNBILLED REVENUE 375 000 1040
WY-PPL
05COSLO057-CO-OWND STR LG 649 99,819 19,088 1538
05CUSL058F-CUST OWND STR 449 402 200 0500
05CUSL058M-CUST OWND STR 767 12,714 0536
05HPSVO051-HI PRESSURE SO 598 679,573 177 25,977 1478
05MVSOO053-MERCURY VAPOR 593 484 129 245 22,829 0866
050AL T015N-OUTD AR LGT SR 390 000 0975
05RFNDCENT-CENTRALIA RFND 168
09SLCOO211-STR LGT CO-OWN 266 000 2660
09SLCU2122-TRAF & OTHER S 158 000 0395
UNBILLED REVENUE
WY-UPL
TOTAL Billed 48,727 564 643 240 940 0542
Total Unbilled Rev.(See Instr. 6)88,58~900,993 111S
TOTAL 48,816,14€653,141 933 054:3
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04
(2) n A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
I Line NumDer ana I me 01 Rate scneaule Mvvn t:iOla Hevenue Average Nurriber I\vvn Of t:iales ~~R~older
No.(a)(b)(c)of cu(~\omers Per C(Jt)stomer (f)
1 09SLCO0211-STR LGT CO-OWN 335 384 730 670 2882
2 09SLCU2121-STR LGT CUST-13,235 500 1454
3 09SLCU2122-TRAF & OTHER S 2,487 357 0332
4 UNBILLED REVENUE 34,001 6539
5 Less Multiple Billings 624
Total Public Street & Hwy. - 444 160,911 16,037 366 368 36,839 0997
9 Other Sales to Public Authorities
UT-UPL
08GNSVOO06-GEN SRVC-DISTR 61,958 894 619 195,800 0467
08GNSVOO09-GEN SRVC-HI VO 17,279 596.793 639,500 0345
08GNSVO023-GEN SRVC-DISTR 470 333 0636
08GNSVO09M-MANL HIGH VOLT 452,149 987 206 113,037 250 0354
080AL TO07N-SECURITY AR LG 273 000 1780
UNBILLED REVENUE 511 215,000 0390
Less Multiple Billings
Total Other Sales to Public Auth.537,007 19,703,361 889,148 0367
Interdepartmental Sales
W A-PPL
02GNSVO024-WA GEN SRVC 139 0695
Total Interdepartmental - 448 139 0695
Forfeited Discounts
CA-PPL
Late Fee 211,328
ID-UPL
Late Fee 227 695
OR-PPL
Late Fee 009 203
UT-UPL
Late Fee 138,028
W A-PPL
Late Fee 350 651
WY -PPL
Late Fee 321 476
WY-UPL
TOTAL Billed 48,727 56'643,240,940 054~
Total Unbilled Rev.(See Instr. 6)58~900 993 111 S
TOTAL 48,816,14E 653,141 933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) Ei A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues, II Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
iLine Numoer ana Iitle or Hate scneaule Mwn ~ola Hevenue Average Numoer I.S.vvn OT ~ales ~~~forderNo.(a)(b)(c)of C~~~omers Per 9~stomer
(f)
1 Late Fee 691
Total Forfeited Discounts - 450 323 072
5 Miscellaneous Service Revenues
CA-PPL
06CFROOO03-MTH MAINTENANC 454
8 06CONN0300-CA RECONNECTIO 651
9 06RCHK0300-CA RET CHK CHR 103
06TAMP0300-CA TAMP & UNAU 615
06TEMP0300-CA TEMP SRVC C 11 ,050
06TRBL0300-CA TROUBLE CAL
06XTNTHEFT - TAMPER & RECON 315
Energy Finanswer new Com 372
Home Comfort 653
Industrial Finanswer 559
Irrigation Finanswer 671
weatherization Loans 8%119
ID-UPL
07CFROOO01-MTH FAC SRVCHG 100
07CONN0300-ID RECONNECTIO 86,925
07FCBUYOUT - FAC CHG BUYOUT 372
07RCHK0300-ID RET CHK CHR 770
07TAMP0300 025
07TEMPO014-TEMP SRVC CONN 740
Energy Finanswer new Com 468
Other 182
Weatherization Loans ID 652
OR-PPL
01CFROOO03-MTH MAINTENANC 29,792
01 CFROO013-MTH MISC CHRG 513
01CFROO014-YR MISC CHRG
01 CONN0300-RECONNECTION C 771 850
01 ESSC0600 - ESS charges 392
01 FCBUYOUT-FAC CHG BUYOUT 451
01 HAFGOO11-HSLE FREE GUAR
01 MISCOOOO-FEE OFFERING N
01 MTRVR300-METR VERIF FEE 360
01 RCHK0300-RETURNED CHECK 199 050
01TAMP0300-TAMP & UNAUTH 475
TOTAL Billed 48,727 564 643,240 940 0542
Total Unbilled Rev.(See Instr. 6)88,582 900,993 1118
TOTAL 48,816,146 653,141 933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) Fi A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE S(,HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
I LIne Number ana Titre Omare scneoUie Mwn t)OIO Hevenue Average Numoer ~wn OT ~ales ~~R~older
No.of Cu~\omers Per C(~stomer
(a)(b)(c)(f)
1 OHEMP0300-TEMP SRVC CHRG 352,575
2 01TRBL0300-TROUBLE CALL C 149
3 01XTNTHEFT - TAMPER & RECON 13.586
4 Hassel Free Water Heater 813
5 Irrigation Finanswer 714
6 Misc Serv-Acct Serv Chrg 454
7 Other 5,466
8 Weatherization Loans 10 110
9 UT-UPL
08CFROO013-MTH MISC CHRG 141 331
08CFROO051-MTH FAC SRVCHG 198,719
08CFROO052-ANN FAC SVCCHG 424
08CFROO056-MTH EOUIP RENT 101
08CFROO063-MTH MISC CHARG 301
08CFROO064-ANN MISC CHARG 660
08CON N0300-R ECONN&DI SCON N 772,569
08FCBUYOUT-FAC CHG BUYOUT 150,446
08INFO0300-CUST/3RD P REO
08MTRVR300 - Meter Verification F 365
08NCON0300-UT FEE NRES RE 243
08RCHK0300-UT RET CHK CHR 225 780
08RCONOO01-CONNECT FEE 691 380
08SPCLOO07-SPECL FAC CHRG 19,609
08T AMP0300- T AMPERING&UNAU 225
08TEMPO014-TEMP SRVC CONN 896,245
08XTNTHEFT - TAMPER & RECON 271
Energy Finanswer 12,000 255
Energy Finanswer new Com 264 740
Industrial Finanswer 603
Other -3,431
Retrofit Finanswer 925
W A-PPL
02CFROOO03-MTH MAINTENANC 320
02CONN0300-W A RECONNECTIO 145,575
02FCBUYOUT - FAC CHG BUYOUT 211
02RCHK0300-W A RET CHK CHR 25,856
02TAMP0300-WA TAMP & UNAU 250
02TEMP0300-WA TEMP SRVC C 960
02XTNTHEFT - TAMPER & RECON
Energy Finanswer new Com 20,805
TOTAL Billed 48,727 56~643,240,940 0542
Total Unbilled Rev.(See Instr. 6)582 900 993 111 S
TOTAL 48,B16,14€653,141 933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SC HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues, II Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line NumDer ana Ime OT Hate scneaUie Mwn ~ola Hevenue Average Numoer ~vvn oT ~ales ~W~~olderNo.(a)(b)(c)of c~~~omers Per 1~stomer (f)
1 Home Comfort 16,687
2 Industrial Finanswer 093
3 Other 605
4 WY-PPL
5 05CFROOO03-MTH MAINTENANC 032
6 05CFROO013-MTH MISC CHRG 186
7 05CONN0300-WY RECONNECTIO 255
8 05FCBUYOUT - FAC CHG BUYOUT 064
9 05RCHK0300-WY RET CHK CHR 30,270
05SERV0300-WY SRVC CALLS 720
05T AMP0300 350
05TEMP0300-WY TEMP SRVC C 375
Energy Finanswer new Com 099
Other 22,507
WY -UPL
05CONN0300-WY RECONNECTIO 330
05FCBUYOUT - FAC CHG BUYOUT 54,958
05RCHK0300-WY RET CHK CHR 900
05SERV0300-WY SRVC CALLS 360
05TAMP0300 300
05TEMP0300-WY TEMP SRVC C 720
05XTNTHEFT - TAMPER & RECON
09CFROOO01-MTH FAC SRVCHG 586
09CFROO014-YR MISC CHRG
Energy Finanswer 12 000 687
Total Misc. Servo Rev. - 451 691 582
Sales of Water & Water Power 170 132
WATER & WATER PWR SALES
Total Sales of Water - 453 170,132
Rent from Electric Property
CA-PPL
06CFROOO06-MTH RNT AL CHRG 710
MCI Fiber Optic Grou 293,555
RENT REVENUE-HYDRO 56,099
RENT REV-TRANSMISS
RENT REV-DISTRIBUT 099
TOTAL Billed 48,727 564 643 240 940 0542
Total Unbilled Rev.(See Instr. 6)88,582 900,993 111 S
TOTAL 48,816 14~653,141 933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
I Line NumDer ana Iltle or Hate scneoUie Mwn ~ola Hevenue Average NumDer ~wn- or ~ales ~~R~order
No.(a)(b)(c)of c~~)omers Per ?~stomer (f)
1 Joint Use 198,834
2 ID-UPL
3 07CFROOO09-YR LSE CHRG-EO 873
07INVCHGOO-INVEST MNT CHG 180
5 07LOOPO014-MTH FEE PRE-581
6 07POLEO075-STEEL POLES US 312
7 07XTRNO013-RNT/LSE L& PRO 103 108
8 RENT REVENUE-HYDRO 535
9 RENT REV-GEN(COMM)700
Joint Use 121 242
OR-PPL
01 CFROOO06-MTH RNT AL CHRG 611 304
Rent Revenue 233,250
Rents - Non Common 66,610
MCI Fiber Optic Grou 057 710
RENT REVENUE-HYDRO 543
RENT REV-TRANSMISS 193,604
RENT REV-DISTRIBUT 524
RENT REV-GEN(COMM)188
Joint Use 368 860
UT-UPL
08CFROO058-MTH EOUIP LEAS 842 067
08INVCHGON-INVEST MNT CHG 062
08INVCHGOR-INVEST MNT CHG 354
08LOOP014N-TEMP SERV CONN 23,463
08POLEOO04-POLE A TT ACHMEN 093
08POLEO075-STEEL POLES US 116 631
08XTRNO013-RNT/LSE L& PRO 75,184
Rent Revenue 422
Rents - Non Common 235
RENT REVENUE-STEAM 151 163
RENT REVENUE-HYDRO 144 353
RENT REV-TRANSMISS 519,316
RENT REV-DISTRIBUT 59,826
RENT REV-GEN(COMM)468 664
Joint Use 092 770
W A-PPL
02CFROOO01-MTH FACILITY S 233
02CFROOO06-MTH RNT AL CHRG 31,469
Rents - Non Common 673
TOTAL Billed 48,727,564 643,240,940 0542
Total Unbilled Rev.(See Instr. 6)88,582 900,993 1118
TOTAL 48,816,146 653,141,933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04(2) D A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SC"HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
I Line NumDer ana Ime Of Mate scneaUie Mvvn ~ola Hevenue Average Numoer ISwn oT ~ales ~~R~older
No.(a)(b)(c)of c~~~omers Per C(~stomer
(1)
1 RENT REVENUE-HYDRO 497,607
2 RENT REV-DISTRIBUT 473
3 RENT REV-GEN(COMM)31,047
Joint Use 928,188
5 WY -PPL
6 05CFROOO01-MTH FACILITY S 20,600
7 05CFROOO06-MTH RNTAL CHRG 747
8 RENT REVENUE-STEAM 27,199
RENT REV-TRANSMISS 500
RENT REV-GEN(COMM)176
Joint Use 205,374
WY-UPL
09LOOP0214-MTH FEE PRE-584
09POLEO075-STEEL POLES US 19,850
Rent Revenue 170
RENT REVENUE-STEAM 033
RENT REVENUE-HYDRO 400
RENT REV-TRANSMISS 525
RENT REV-DISTRIBUT 16,160
RENT REV-GEN(COMM)45,978
Joint Use 45,003
Total Rent from Elect. Prop. - 45 838 870
Other Electric Revenues
General Office
WHEELING ESTIMATE 49,950
Trading Netted 96,569
OTH ELEC ESTIMATE 491,974
GREEN CREDIT SALES 579,156
Bookouts Netted 352 722
Other Elec (exclud Wheel)15,167,262
Post Merg Firm Wheeling 588,065
CA-PPL
DSM REV-CA sac OFF 42,221
Fish, Wildlife, Recr 672
ID-UPL
Other Elec (exclud Wheel)199 199
OR-PPL
01 CFROOO01-MTH FACILITY S 87,106
TOTAL Billed 48,727,56~643,240,940 0542
Total Unbilled Rev.(See Instr. 6)88,58~900 993 1118
TOTAL 816,14E 653,141 933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE SCHEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line Numoer ana Iitle or Hate scnedule Mwn ~Old Hevenue Average Numoer ~vvn OT ~ales ~VlR'WolderNo.(a)(b)(c)of C~~)omers Per y~stomer
(f)
1 01 CFROOO04-EMRGNCY ST&BY 484
2 01 CFROOO05-INTERMTNT SRVC 911
3 DSR Net Lost Revenue 466,439
4 DSR RENEW ABLES 423,857
5 DSR DEFERRED EXPEN 606
6 DSR Incentive Mechanisms 156,505
INTERCO FIRM WHEEL 229 096
8 INTERCO NON-FRM WHEEL 498
9 Non-Firm Wheeling 143 772
Other Elec (exclud Wheel)864 536
Other Elec DSR carry chrg 721 532
Other Elec DSR Def Amort 426 684
Post Merg Firm Wheeling 505 386
Pre Merg Firm Wheel PPL 866,494
Pre Merg Firm Wheel UPL 943,145
Rec Wheeling Rev 999,330
Short-term Firm Wheeling 987 082
UT -UPL
08CFROO053-MTHL Y MAINTFEE 619
08XTRNO016-0UTBIL SVC REN 249 153
ELEC INC-OTHR 255,767
FL Y ASH SALES 69,208
DSM REV-UT sac OFFSET 073 192
Fish; Wildlife, Recr 099
Other Elec (exclud Wheel)357,300
W A-PPL
02CFROOO04-EMRGNCY ST&BY 990
02CFROOO05-INTERMTNT SRVC 218
DSM REV-WA sac OFF 379 277
Fish, Wildlife, Recr 554
Other Elec (exclud Wheel)570,973
Other Elec DSR carry chrg -5,833
Wash Colstrip 3 52,188
WY-PPL
05CFROOO04-EMRGNCY ST&BY 623
05CFROOO05-INTERMTNT SRVC 10,664
09CFROOO05-INTERMTNT SRVC 339
ELEC INC-OTHR 156,499
FLY ASH SALES 791 126
TOTAL Billed 727 564 643,240 940 0542
Total Unbilled Rev.(See Instr. 6)582 900,993 1118
TOTAL 48,816 146 653,141 933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SALES OF ELECTRICITY BY RATE S( HEDULES
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues, II Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
LIne r~umcer ana I !tie or Hale scneoUie MwnSolC Hevenue -p,veragel'Jumcer ISwn oT ~ales ~~R~orderNo.(a)(b)(c)of Cus~omers Per 9.~stomer
(f)
1 Other Elec (exclud Wheel)583
2 WY-UPL
3 FLYASH SALES 840
5 Total Other Electric Rev. - 456 123 695 302
TOTAL Billed 48,727,564 643 240 940 0542
Total Unbilled Rev.(See Instr. 6)582 900,993 111 a
TOTAL 816 146 653,141 933 0543
FERC FORM NO.1 (ED. 12-95)Page 304.
Blank Page
(Next Page is: 310)
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) D A Resubmission 04/25/2005
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
Requirement Sales
Brigham City 318
Brigham City
Deaver, Town of
Helper City
Helper City Annex
Navajo Tribal Utility Authority (Mexic)
Navajo TiI~al Utility Authority (Red M)T-6
Portland General Electric Co.147
Portland General Electric Co.147
Price City
Accrual True-up
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2004/04(2) D A Resubmission 04/25/2005
SALES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. Atter listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) atter this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column m. Explain in a footnote all components of the amount shown in column m. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
93,449 414 226 627 879 042,105
16,733 234,654 291,544 526,198
935 726 860 586
751 104,590 101 869 206,459
594 047 63,667 131 71-4
048 20,303 18,263 38,566
641 75,649 80,838 156,487
388
105 877 974 877 974
526 988 740 124 914 113 65-4
217 28,898
201 494 919,935 203,808 286 155 029
155 486 020,354 132 926 924 892 132,588 320 814 690
13,356,980 940,289 137 130,732 -892 101 302 327 969,719
FERC FORM NO.1 (ED. 12-90)Page 311
Name of Respondent This wrt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) D A Resubmission 04/25/2005
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy. capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Avera AveracationTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
Nonrequirement Sales
American Electric Power WSPP
Anaheim, City of WSPP
Arizona Public Service Co.
Arizona Public Service Co.
Avista Corp.WSPP
Avista Corp.WSPP
Avista Energy, Inc.WSpp
Avista Energy, Inc.WSPP
BP Energy Company WSPP
Basin Electric Power Cooperative
Basin Electric Power Cooperative
Basin Electric Power Cooperative WSPP
Basin Electric Power Cooperative WSPP
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
his ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
SALES FOR RESALE (Account 447 Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-ROil amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2004/04Name of Respondent
PacifiCorp
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
094 900 33,371 967 33,371 967
600 433,200 433,200
39,038 630 969 630,969
641,204 74,475,948 478,111
800
39,169 812,790 817,711
750
307,111 587 223 12,587 223
1 ,033,096 530,740 44,530 740
047 885
119 126 962
879 864 88,864
11 ,228 611,880 611,880
201,494
13,155,486
919 935
020,354
203,808
132 926,924
286
892 132 588
155,029
320,814 690
13,356,980 940,289 137,130,732 -892,101,302 327,969 719
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This wrt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the suppliers service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term " means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Aver AveracationTariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
Benton County Public Utility District WSPP
Black Hills Power, Inc.236
Black Hills Power, Inc.WSPP
Black Hills Power, Inc.WSPP
Blanding City
Bonneville Power Administration 543
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration WSPP
British Columbia Transmission Corp.
Burbank, City of WSPP
California Independent System Operator
California Independent System Operator
Calpine Energy Services, loP.WSPP
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report(1) An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
SALES FOR RESALE Account 447) (Continued
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliers system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2004/04
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
775 278,830 278,830
365,378 151 395 827 239 978,634
004 009,486 009,486
038 920,656 920 656
12,872 180,000 333,386 513,386
474 336 157 876 157 876
39,569 742,223 742 223
512
143,874 466 127 468 352
096
132 384 970,429
100 4,431
200,671 480 779 480
122 122
201,494
13,155,486
919 935
80,020 354
203,808
132 926,924
286
892,132 588
155,029
320 814 690
13,356,980 82,940,289 137,130,732 -892,101,302 327,969,719
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition , the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
Cargill Power Markets, LLC T-12
Cargill Power Markets, LLC
Cargill Power Markets, LLC
Cargill Power Markets, LLC
Chelan County Public Utility District WSPP
Clark Public Utilities
Clark Public Utilities
Clatskanie Peoples Utility District WSPP
Colorado River Commission of Nevada WSPP
Colorado Springs Utilities WSPP
Colorado Springs Utilities WSPP
Conoco Inc.
Conoco Inc.
Conoco Inc.
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales , enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The nSubtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2004/04Name of Respondent
PacifiCorp
MegaWatt Hours REVENUE Line
Sold Demand Charges Energy Charges Other Charges Total ($)
No.
($)($)($)
(h+i+j)
(g)
(h)(i)(k)
172
28,536 134,952
384 144 946 144 946
276,604 13,015,589 13,015,589
800 900 725
256,883
177 120 765,613 586 680 352 293
800 700 700
600 77,600 600
556 167 549 167 549
807 383,453 383,453
625 625
141
177 830 372 586
201 494
13,155,486
919,935
80,020,354
203,808
132,926,924
286
892,132 588
155,029
320,814 690
13,356,980 940,289 137,130,732 -892 101,302 327 969,719
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera AveracationTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
Constellation Power Source, Inc.
Constellation Power Source, Inc.
Coral Power
Coral Power WSPP
Cowlitz County Public Utility Dist 234
Deseret Generation & Transmission
Douglas County Public Utility Dist WSPP
Duke Energy Trading & Marketing, LLC
Duke Energy Trading & Marketing, LLC
Duke Energy Trading & Marketing, LLC
ENMAX Energy Marketing Inc.WSPP
EPCOR Merchant and Capital Inc.WSPP
EI Paso Electric Company WSPP
EI Paso Electric Company WSPP
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2004/04
(2) Lj A Resubmission 04/25/2005
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal- RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column m. Explain in a footnote all components of the amount shown in column m. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges No.
($)($)($)
(h+i+j)
(g)
(h)(i)(k)
030 588,967 588,967
197 553 49,763 206 763,206
540 7:~16,763
082,350 693,939 693 939
50,736 778 256 778,256
075
249 11,220 11 ,220
533
20,173 890,399 890 399
1 ,726,093 090,954 61,090,954
712 110,210 110 210
133 348,450 348,450
080 000 000
26,675 198.548 1 ,198,548
201 494 919,935 203,808 286 155 029
13,155 486 80,020,354 132 926.924 892 132 588 320,814 690
13,356,980 82,940,289 137,130,732 -892,101,302 327,969,719
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SALES FOR RESALE (Account 447f
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
Entergy-Koch Trading, loP.WSPP
Eugene Water & Electric Board
Eugene Water & Electric Board WSPP
FPL Energy Power Marketing, Inc.WSPP
Flathead Electric Cooperative
Franklin County Public Utilities Distr1 WSPP
Grant County Public Utility District 2 WSPP
Grant Co~nty Public Utility District 2 WSpp
Grays Harpor Public Utility District WSPP
Hurricane: City of
IdaCorp Energy
Idaho Fal~s, City of WSPP
Idaho Power Company
Idaho Power Company WSPP
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report(1) I2SJ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2004/04
MegaWatt Hours
Sold
(g)
Demand Charges
($)
(h)
REVENUE
Energy Charges
($)
(i)
Other Charges
($)
Total ($)
(h+i+j)
(k)
Line
No.
157 700
478
481,782
160,100
288,
305
140
750,440
200,640
499,604
879
520
175,484
23,500
149,775
309
200
149 555
180
157 700
481 782
160,100
288,089
305
160
203
425
16,111
855
843
201,494
13,155 486
919,935
80,020,354
203 808
132,926 924
286
892,132 588
155,029
320 814 690
13,356,980 82,940,289 137,130,732 -892 101 302 327 969,719
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RO service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
Idaho Power Company T-11
Idaho Power Company WSPP
J. Aron & Company
J. Aron & Company
Los Angeles Dept. of Water & Power 301
Los Angeles Dept. of Water & Power WSPP
Los Angeles Dept. of Water & Power WSPP
MIECO, Inc.WSPP
Mirant Americas Energy Marketing, L. WSPP
Modesto Irrigation District WSPP
Morgan Stanley Capital Group, Inc.
Morgan Stanley Capital Group, Inc.
Municipal Energy Agency of Nebraska WSPP
Municipal Energy Agency of Nebraska WSPP
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 lED. 12-90)Page 310.
Name of Respondent
PacifiCorp
his ~rt s: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
SALES FOR RESALE Account 447) (Continued
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. Atter listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) atter this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2004/04
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
017 487 676
142 990 575 613 581 988
266
401,492 821 419 17,821 419
590 525 22,457 625 22,457 625
856 324 141 324 141
223 489 212 568 212 568
600 338,800 338,800
29,700 089,212 089 212
800 340,600 340 600
5,473 221 303
684 072 118,574 672 118.574 121
170 065 065
789 380 88,380
201,494
13,155,486
919,935
80,020,354
203,808
132 926,924
31,286
892 132 588
155 029
320 814 690
13,356,980 82,940,289 137,130,732 -892,101,302 327 969,719
FERC FORM NO.1 (ED. 12-90)Page 311.
This ~ort Is:(1) ~ An Original(2) A Resubmission
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RO service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Name of Respondent
PacifiCorp
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
Statistical
Classifi-
cation
(b)(a)
1 NorthWestern Energy
Northern California Power Agency
Occidental Power Services, Inc.
4 PPL Energy Plus, LLC
5 PPL Energy Plus, LLC
6 PPL Montana, LLC
7 PPL Montana, LLC
8 PPL Montana, LLC
Pacific Northwest Generating Coop.
13 Panda Gila River
14 Pinnacle West Capital Corporation
Subtotal RQ
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)
FERC Rate
Schedule orTariff Number
(c)
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
WSPP
Page 310.
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
AverageMonthly Billing
Demand (MW)
(d)
Actual Demand (MW)verage Avera~Monthly NCP Deman Monthly CP-Oeman(e) (f)
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
SALES FOR RESALE (Account 447 (Continued
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of.service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliers system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column m. Explain in a footnote all components of the amount shown in column m. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal. Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2004/04
Name of Respondent
PacifiCorp
MegaWatt Hours REVENUE Line
Sold Demand Charges Energy Charges Other Charges Total ($)
($)($)($)
(h+i+j)No.
(g)
(h)(i)(k)
570 513
9,400 445,100 445 100
175 665,887 665,887
392 392
50,073 621 056 621 056
750
593 83,275
17,429 713 214 713
719 395,011 395,011
439 16,885
18,799 769,770
608 111 740
73,382 934 660 934 660
38,025 712,475 712,475
201 494
13,155 486
919 935
80,020,354
203 808
132 926 924
286
892 132 588
155,029
320 814 690
13,356,980 82,940,289 137 130,732 -892 101,302 327 969,719
FERC FORM NO.1 (ED. 12-90)Page 311.
his F3!f?ort Is:(1) l2S..J An Original(2) A Resubmission
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing vera AveracationTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Portland General Electric Co.T-12
Portland General Electric Co.
Powerex WSPP
Powerex
Powerex
Powerex WSPP
Powerex WSpp
Public Service Company of Colorado WSPP
Public Service Company of Colorado 320 176 173
Public Service Company of Colorado
Public Service Company of Colorado WSPP
Public Service Company of Colorado WSPP
Public Service Company of New Mexico WSPP
Public Service Company of New Mexico WSPP
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
T is ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
S LES FOR RESALE (Account 447 Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column G). Explain in a footnote all components of the amount shown in column G). Report in column (k)the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - ROil amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
005
431,790 075 532
17,538 710 374
12,341 498,909
398 13,966
618 086 62,536,585
195
163,245 29,293,440 56,421 ,
397 297 372
101 888 460,160 460,160
805 975 126,415 41,126,415
187 227 720 233,715
266 501 663 581 12,665,681
201,494
13,155 486
919,935
80,020,354
203,808
132,926 924
286
892 132 588
155,029
320 814 690
13,356,980 82,940,289 137 130,732 -892 101 302 327,969 719
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RO service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly iIIing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
Puget Sound Energy
Puget Sound Energy WSPP
Puget Sound Energy WSPP
Rainbow Energy Marketing WSPP
Rainbow Energy Marketing
Rainbow Energy Marketing WSPP
Redding, City of WSPP
Reliant Energy Services, Inc.
Sacramento Municipal Utility District 250
Sacramento Municipal Utility District 250
Sacramento Municipal Utility District WSPP
Salt River Project WSPP N,o
Salt River Project WSPP
San Diego Gas & Electric WSPP
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
his ~ort s: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
SALES FOR RESALE Account 447 Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
5. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the averagemonthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (50-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column m. Explain in a footnote all components of the amount shown in column m. Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
213 3,411 411
600
188,788 605,492 614 115
1,472 311 311
773 29,908
180 292 660
10,800 752,200
675 450
970,064
569 223 022 185 022 185
953 925,813 925,813
30,200 257 653 257 653
198,432 220,365 220,365
065 252 650 252,650
201,494
13,155,486
919,935
020 354
203,808
132,926,924
286
892 132 588
155,029
320,814 690
13,356,980 940,289 137,130,732 -892 101,302 327 969 719
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the suppliers service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emanc
(a)(b)(c)(d)(e)(f)
Santa Clara, City of WSPP
Seattle City Light WSPP
Sempra Energy Resources
Sempra Energy Trading Corp
Sempra Energy Trading Corp
Sempra Energy Trading Corp
Sierra Pacific Power Company 258
Sierra Pacific Power Company 258
Sierra Pacilic Power Company WSPP
Sierra Pacific Power Company
Sierra Pacific Power Company WSPP
Snohomish Public Utility District No.WSPP
Southern Califomia Edison Company 248
Southern California Edison Company
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent
PacifiCorp
This ~ort s: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
SALES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. Atter listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) atter this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identity the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs underwhich service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the suppliers system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2004/04
MegaWatt Hours REVENUE Line
Sold Demand Charges Energy Charges Other Charges Total ($)No.
($)($)($)
(h+i+j)
(g)
(h)(i)(k)
580 056,771 056,771
831 222,116 226,614
184 012,244 012,
790 411
261 14,365
107,782 85,234 022
198,382
453,158 15,516,000 154 577
14,081 651 028
446 539,626
218 837 10,494 392 494 885
300 778,730 778,730
985,600 59,136 000 136 000
761 952,887 952 887
201 494
13,155,486
919,935
80,020,354
203,808
132,926,924
286
892 132 588
155 029
320,814 690
13,356,980 82,940,289 137,130,732 -892,1 01 ,302 327,969,719
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04
(2) D A Resubmission 04/25/2005
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RD - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RD service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Ave rape Avera
cation Tariff Number Demand (MW)Monthly NC Demanc Monthly CP emand
(a)(b)(c)(d)(e)(f)
State of CA Department of Water Res.311
State of CA Department of Water Res.311 100 100 100
State of CA Department of Water Res.WSPP
Tacoma, City of WSPP
Tractebel Energy Marketing, Inc.WSPP
TransAlta Energy Marketing Inc.WSPP
TransAlta Energy Marketing Inc.
TransAlta Energy Marketing Inc.WSPP
Tri-State Generation & Transmission WSPP
Tri-State Generation & Transmission WSPP
Tri-State Generation & Transmission
Tri-State Generation & Transmission WSPP
Tucson Electric Power WSPP
Tucson Electric Power WSPP
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90\Paae 310.
Name of Respondent
PacifiCorp
his ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
S LES FOR RESALE (Account 447) Continued
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups. for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column G). Explain in a footnote all components of the amount shown in column G). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal- RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Year/Period of Report
End of 2004/04
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
;~qa 33,109
612,709 20,856 000 786,942 642,942
600 506,100 506 100
040 72,615 615
143 223 576,003 576,003
932 932
397 359
407,589 63,440,074 440,074
177 630 262
225
194 641 629,825 648,466
918 407 646 407,646
583 980,045 980 045
201,494
13,155,486
919.935
80,020 354
203,808
132 926 924
286
892 132,588
155,029
320 814 690
13,356,980 82,940,289 137,130,732 -892,101,302 327,969,719
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g" the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RO service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Deman~Monthly CP emand
(a)(b)(c)(d)(e)(f)
UBS Warburg Energy LLC
Utah Associated Municipal Power Systems WSPP
Utah Associated Municipal Power Systems WSPP
Utah Associated Municipal Power Systems
Utah Associated Municipal Power Systems WSPP
Utah Municipal Power Agency 433
Utah Municipal Power Agency 433
Utah Municipal Power Agency
Utah Municipal Power Agency
Western Area Power Administration 313
Western Area Power Administration WSPP
Western Area Power Administration
Western Area Power Administration WSPP
Williams Energy Market & Trading Co.
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SJ LES FOR RESALE (Account 447) (Continued)
as - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal - RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) atter this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column 0). Explain in a footnote all components of the amount shown in column 0). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges No.
($)($)($)
(h+i+j)
(g)
(h)(i)(k)
270,000 12,285,650 285,650
632 62,016 62,016
307 256,241 256,241
542
16,470 942 985 942,985
52,672 681 440 081 988 763 428
220,386 557 825 121 771 679,59€
122 204 204
176 276,814 276,814
465,552 897 664 897 664
55,648 873,801 873,801
152 292 057 057 057 057
011 204 204
201,494 919,935 203 808 286 155 029
155 486 80,020 354 132 926 924 892 132 588 320 814 690
13,356,980 82,940,289 137,130,732 -892,101,302 327,969,719
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SALES FOR RESALE (Account 447)
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RO service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Avera Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly illing Avera AveracationTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
Bookout Sales
Bookout Sales
Trade Sales
Accrual True-up
Subtotal RO
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
his 1!?ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
S LES FOR RESALE (Account 447) (Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RO sales together and report them starting at line number one. After listing all RO sales, enter "Subtotal- RO"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RO" in column (a) after this Listing. Enter
Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RO sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RO/Non-RO grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal- RO" amount in column (g) must be reported as Requirements Sales For Resale on Page
401 , line 23. The "Subtotal - Non-RO" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Sold
(g)
Demand Charges
($)
(h)
REVENUE
Energy Charges
($)
(i)
Other Charges
($)
Total ($)
(h+i+j)
(k)
305,292
544 418,420
92,892,
092
Line
No.
15,658
15,212 367
201,494
13,155,486
919,935
80,020,354
203,808
132 926,924
286
-892 132 588
155 029
320 814 690
13,356,980 82,940,289 137,130,732 -892,101,302 327 969,719
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) Ei A Resubmission 04/25/2005
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account C'tmoun ~or Amount for
No.urrent ear Previous Year
(a)(b)(c)
1. POWER PRODUCTION EXPENSES
A. Steam Power Generation
Operation
(500) Operation Supervision and Engineering 257,545 127 532
(501) Fuel 431 677 442 413 813,285
(502) Steam Expenses 429,428 516,809
(503) Steam from Other Sources 158,192 095 133
(Less) (504) Steam Transferred-Cr.
(505) Electric Expenses 066,800 632 110
(506) Miscellaneous Steam Power Expenses 32,636,462 35,730 308
(507) Rents 079,460 650,986
(509) Allowances
TOTAL Operation (Enter Total of Lines 4 thru 12)525,305 329 513,566,163
Maintenance
(510) Maintenance Supervision and Engineering 708,500 387 155
(511) Maintenance of Structures 898,725 18,074 348
(512) Maintenance of Boiler Plant 84,815,260 80,318,515
(513) Maintenance of Electric Plant 124 302 30,327 174
(514) Maintenance of Miscellaneous Steam Plant 738,019 848,721
TOTAL Maintenance (Enter Total of Lines 15 thru 19)150,284,806 145,955 913
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)675 590 135 659,522 076
B. Nuclear Power Generation
Operation
(517) Operation Supervision and Engineering
(518) Fuel
(519) Coolants and Water
(520) Steam Expenses
(521) Steam from Other Sources
(Less) (522) Steam Transferred-Cr.
(523) Electric Expenses
(524) Miscellaneous Nuclear Power Expenses
(525) Rents
TOTAL Operation (Enter Total of lines 24 thru 32)
Maintenance
(528) Maintenance Supervision and Engineering
(529) Maintenance of Structures
(530) Maintenance of Reactor Plant Equipment
(531) Maintenance of Electric Plant
(532) Maintenance of Miscellaneous Nuclear Plant
TOTAL Maintenance (Enter Total of lines 35 thru 39)
TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)
C. Hydraulic Power Generation
Operation
(535) Operation Supervision and Engineering 806,096 172 631
(536) Water for Power 137 864 594
(537) Hydraulic Expenses 371,194 178,553
(538) Electric Expenses 379
(539) Miscellaneous Hydraulic Power Generation Expenses 16,213,098 15,982.757
(540) Rents 880 63,955
TOTAL Operation (Enter Total of Lines 44 thru 49)25,619,511 19,445,490
FERC FORM NO.1 (ED. 12-93)Page 320
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) Ei A Resubmission 04/25/2005
ELECTRIC OPERATION AND MAINTENANCE E ",PENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account &moun~or Amount for
No.urrent ear Previous Year
(a)(b)(c)
C. Hydraulic Power Generation (Continued)
Maintenance
(541) Mainentance Supervision and Engineering
(542) Maintenance of Structures 338,314 334 959
(543) Maintenance of Reservoirs, Dams, and Waterways 223,292 927 384
(544) Maintenance of Electric Plant 849 609 856,545
(545) Maintenance of Miscellaneous Hydraulic Plant 232 872 570,548
TOTAL Maintenance (Enter Total of lines 53 thru 57)644 087 689,436
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)34,263,598 134,926
D. Other Power Generation
Operation
(546) Operation Supervision and Engineering 633 324 990
. (547) Fuel 848,687 79,846,121
! (548) Generation Expenses 531,091 10,602 938
I (549) Miscellaneous Other Power Generation Expenses 514 891 309 653
(550) Rents 17,445 992 322 784
TOTAL Operation (Enter Total of lines 62 thru 66)96,349,294 109,406,486
Maintenance
(551) Maintenance Supervision and Engineering
(552) Maintenance of Structures 100,727 57,728
(553) Maintenance of Generating and Electric Plant 484 838 253 569
(554) Maintenance of Miscellaneous Other Power Generation Plant 161,782 110,059
TOTAL Maintenance (Enter Total of lines 69 thru 72)747,347 421 356
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)096,641 109,827 842
E. Other Power Supply Expenses
(555) Purchased Power 936,220,986
(556) System Control and Load Dispatching 767,418 791,513
(557) Other Expenses 35,360,885 25,637 611
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)404 781 490 963,650 110
TOTAL Power Production Expenses (Total of lines 21,41,59,74 & 79)211 731,864 760,134,954
2. TRANSMISSION EXPENSES
Operation
(560) Operation Supervision and Engineering 086,302 698,187
(561) Load Dispatching 072 585 118 246
(562) Station Expenses 036,952 306,701
(563) Overhead Lines Expenses 344,708 174,929
(564) Underground Lines Expenses
(565) Transmission of Electricity by Others 76,944,428 497 156
(566) Miscellaneous Transmission Expenses 40,424 363,108
(567) Rents 574 819 405,585
TOTAL Operation (Enter Total of lines 83 thru 90)90,100,218 563,912
Maintenance
(568) Maintenance Supervision and Engineering 626 211
(569) Maintenance of Structures 466 143
(570) Maintenance of Station Equipment 829 952 836,308
(571) Maintenance of Overhead Lines 170,446 466,454
(572) Maintenance of Underground Lines 593 10,318
(573) Maintenance of Miscellaneous Transmission Plant 187,444 80,415
TOTAL Maintenance (Enter Total of lines 93 thru 98)223,527 397 849
100 TOTAL Transmission Expenses (Enter Total of lines 91 and 99)105 323,745 105 961 761
101 3. DISTRIBUTION EXPENSES
102 Operation
103 (580) Operation Supervision and Engineering 23,633,967 23,764 850
FERC FORM NO.1 (ED. 12-93)Page 321
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
ELECTRIC OPERATION AND MAINTENANCE EKPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account 6'tmoun ~or Amount
No.urrent ear Previous ear
(a)(b)(c)
104 3. DISTRIBUTION Expenses (Continued)
105 (581) Load Dispatching 297 006 417 993
106 (582) Station Expenses 839,640 833,459
107 (583) Overhead Line Expenses 543,306 17,824 024
108 (584) Underground Line Expenses 895 579 710,938
109 (585) Street Lighting and Signal System Expenses 288,258 39,868
110 (586) Meter Expenses 319,872 414,421
111 (587) Customer Installations Expenses 119 129 276,892
112 (588) Miscellaneous Expenses 22,322,195 10,201 170
113 (589) Rents 587 250 707 201
114 TOTAL Operation (Enter Total of lines 103 thru 113)88,846 202 190,816
115 Maintenance
116 (590) Maintenance Supervision and Engineering 972,442 938,431
117 (591) Maintenance of Structures 083,885 1 ,227,236
118 (592) Maintenance of Station Equipment 299,708 755 471
119 (593) Maintenance of Overhead Lines 389 411 240,458
120 (594) Maintenance of Underground Lines 23,963,619 22,701 989
121 (595) Maintenance of Line Transformers 269,880 817 032
122 (596) Maintenance of Street Lighting and Signal Systems 228,547 756,529
123 (597) Maintenance of Meters 978 990 727,266
124 (598) Maintenance of Miscellaneous Distribution Plant 849 987 777 010
125 TOTAL Maintenance (Enter Total of lines 116 thru 124)120,036,469 63,941,422
126 TOTAL Distribution Exp (Enter Total oflines 114 and 125)208 882 671 135 132 238
127 4. CUSTOMER ACCOUNTS EXPENSES
128 Operation
129 (901) Supervision 247 491 212 237
130 (902) Meter Reading Expenses 23,316,877 233 313
131 (903) Customer Records and Collection Expenses 710,918 496 740
132 (904) Uncollectible Accounts 6,409,944 345 071
133 (905) Miscellaneous Customer Accounts Expenses 138,185 129,040
134 TOTAL Customer Accounts Expenses (Total of lines 129 thru 133)86,823 415 96,416,401
135 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
136 Operation
137 (907) Supervision 931 564 935,290
138 (908) Customer Assistance Expenses 32,567 629 272,111
139 (909) Informational and Instructional Expenses 000 992 918 419
140 (910) Miscellaneous Customer Service and Informational Expenses 322 661 454 703
141 TOTAL Cust. Service and Information. Exp. (Total lines 137 thru 140)37,822 846 580,523
142 6. SALES EXPENSES
143 Operation
144 (911) Supervision
145 (912) Demonstrating and Selling Expenses
146 (913) Advertising Expenses
147 (916) Miscellaneous Sales Expenses 196 329
148 TOTAL Sales Expenses (Enter Total of lines 144 thru 147)196,329
149 7. ADMINISTRATIVE AND GENERAL EXPENSES
150 Operation
151 (920) Administrative and General Salaries 110,959 772 123,397,636
152 (921) Office Supplies and Expenses 16,425 981 298 451
153 (Less) (922) Administrative Expenses Transferred-Credit 25,662,239 549 333
FERC FORM NO.1 (ED. 12-93)Page 322
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
ELECTRIC OPERATION AND MAINTENANCE E PENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount forNo Current Year
154 7. ADMINISTRATIVE AND GENERAL EXPENSES (Continued)
155 (923) Outside Services Employed
156 (924) Property Insurance
157 (925) In uries and Dama es
158 (926 Emplo ee Pensions and Benefits
159 (927) Franchise Re uirements
160 (928) Regulatory Commission Expenses
161 (929) (Less) Duplicate Charges-Cr.
162 930.1) General Advertisin E enses
163 (930.2) Miscellaneous General Expenses
164 (931) Rents
165 TOTAL Operation (Enter Total of lines 151 thru 164)
166 Maintenance
167 935) Maintenance of General Plant
168 TOTAL Admin & General Ex enses (Total of lines 165 thru 167)
169 TOTAL Elec Op and Maint Expn (Tot 80, 100, 126, 134, 141 , 148,168
Amount forPrevIous Year
(c)
233,211
15,324 108
539 322
41,233,447
783,382
225,169,932
871,252
043 242
409,968
40,071 989
630 562
221 570,755
19,723,050
244 892,982
895,477 523
29,785,769
251,356,524
361 778 730
FERC FORM NO.1 (ED. 12-93)Page 323
Name of Respondent This Re IOrt Is:Date of Report Year/Period of Report
PacifiCorp (1) .~ An Original (Mo, Da, Yr)End of 2004/04(2) A Resubmission 04/25/2005
~CHA~ED POWER ~Accou~t 5 5)nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Power Purchases
Alta Energy LLC
Alta Energy LLC
American Electric Power
Anaheim , City of
Aquila Merchant Services, Inc.
Aquila Merchant Services, Inc.
Arizona Public Service Co.
Arizona Public Service Co.
Arizona Public Service Co.
!::
Arizona Public Service Co.
Arizona Public Service Co.
Avista Corp.
Avista Corp.
Total
FERC FORM NO.1 (ED. 12-90)Page 326
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGESMegaWatt Hours
Purchased MegaWatt Hours MegaWatt HoursReceived Delivered
(~
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
Demand Charges
($)(j)
49,
557
318
146,40
246,
73,
1,490,
267
274,
751
66,995,
999,
15,594,487 902 326 13,264 299 974 015,269106,195,300 235,473,156
FERC FORM NO.1 (ED. 12-90)Page 327
LineTotal O+k+l) No.of Settlement ($)
(m)
168
49,654
49,557 084
668,192
158 681
337 695
700
267 608
237,092
751 848
66,995 064
900
014 319
367 653,
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
PU~CHA~ED POWER ~ACCOU)t 5 5)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm " means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Avista Energy, Inc.
Avista Energy, Inc.
BP Energy Company
Ballard Hog Farms Inc.
Beaver City
Bell Mountain Power
Benton County Public Utility District
Biomass One, loP.22.23.20.
Birch Creek Hydro
Black Hills Power & Light Company
Black Hills Power & Light Company
Black Hills Power & Light Company
Black Hills Power & Light Company
Black Hills Wyoming, Inc.
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
his ~ort Is:(1) l!.J An Original(2) A Resubmission
ccounnc udln po er exchange)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04Name of Respondent
PacifiCorp
4. In column (c), identity the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (t). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGESMegaWatt Hours
Purchased MegaWatt Hours MegaWatt HoursReceived Delivered
(g)
(h) (i)
398
847
001
175,
15,
COST/SETTLEMENT OF POWER Line
Demand Charges Energy Charges Other Charges Total O+k+l)No.
($)~~~
\f?
of Settlement ($)
(m)
200
258 711 18,258 711
42,883,39,034,484
095 179
809
45,780
483,483 210
199,500 555,754 799
775,891 775 891
341
826,090
284,688
147 611
340
594,487 12,902,326 13,264 299 106 195,300 235,473,156 974 015,269 367,653
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This I ort Is:Date of Report Year/Period of Report
PacifiCorp
(1)An Original (Mo, Da, Yr)End of 2004/04
(2)A Resubmission 04/25/2005
~CHA~ED POWER ~Accou~t 555)nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Black Hills Wyoming, Inc.
Bogus Creek
Bonneville Power Administration
Bonneville Power Administration 663 663 491
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Boston Power
Boston Power
Burbank, City of
CDM Hydro
California Independent System Operator
California Independent System Operator
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column G), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered
~~~
\fl
of Settlement ($)
Jg)(h)(i)(m)
677 677 495
36,36,
240,000
055,500 055 500
060,533
463,351
179,520
17,629,203
301
648 19,710
248 558
25,280,948
522
370 12,640,12,640,515
15,594,487 12,902 326 13,264 299 106,195,300 235,473,156 -974 015 269 367,653,
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
PU~CHA~ED POWER ~Accou~t 555)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition , the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Calpine Energy Services, loP.
Calpine Energy Services, loP.
Cargill Power Markets, LLC
Cargill Power Markets, LLC
Central Oregon Irrigation District 1.8
Chelan County Public Utility District
Chelan County Public Utility District
Chelan County Public Utility District
Chelan County Public Utility District
City of Buffalo
Clark Public Utilities
Clatskanie People s Utility District
Colorado Springs Utilities
Colorado Springs Utilities
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent
PacifiCorp
Date of Report(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
ccounncludlng po er exchange)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliers system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.Received Delivered
($)
of Settlement ($)
(g)
(h)(i)(I)(m)
37,
107,49 170,170,813
112,112,259
277 401 612,921 610,481
17,285 637 370,655,712
42,
297 317 316
13,750
65,121 966 972 393
22,522 102 125,480
177 483 483 320
48,48,600
407
16,16,704
15,594,487 12,902 326 13,264,299 106,195,300 235,473,156 -974 015,367 653,
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
~CHA~ED POWER ~Accou~t 555)nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Commercial Energy Management
Conoco Inc.
Conoco Inc.
Constellation Power Source, Inc.
Constellation Power Source, Inc.
Coral Power
Cowlitz County Public Utility District
Curtiss Livestock
DR Johnson Lumber Company
Davis County Waste Management
Deschutes Valley Water District
Deseret Generation & Transmission
Desert Power, loP.
Douglas County Public Utility District
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04
(2) LI A Resubmission 04/25/2005
. .... ...... ". .~. '-
)WE,
CCOU
R\~g~~) (ContinUed)nCiuding po er exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column m, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.Received Delivered
($)~~~
\fl
of Settlement ($)
(g)
(h)(i)
(j)
(m)
82E 126 130
30C 13,20C 13,200
139,10C 498,42E 498,426
60C 177,52C 177 520
910,34E 271,087
-~~~~q~
39,346,087
1 ,202 34~486 682 486 683
-577 310
100 375 375
24€783,495 844,32€627 821
324 11,304 304
314 547 311 874 590 3,421 901
329 329
721 30,927 30,927
497
15,594,487 12,902 326 13,264 299 106 195 300 235,473 156 974 015 269 367 653 187
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
~CHA~ED POWER ~Accou~t 5 5)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Douglas younty Public Utility District
Douglas C~unty Public Utility District
Douglas County Public Utility District
Draper Irrigation Company
Dry Creek
Duke Energy Trading & Marketing, LLC
Duke Energy Trading & Marketing, LLC
Duke Energy Trading & Marketing, LLC
Dynegy Power Marketing
EN MAX Energy Marketing Inc.
EPCOR Merchant and Capital Inc.
Eagle Point Irrigation District 0.4
EI Paso Electric Company
EI Paso Electric Company
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004104
(2) D A Resubmission 04/25/2005
IJI IC "1 CCOU
~\~g~~J (ContinUed)
. ... ....,
. (Including" power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (D, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges. report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.Received Delivered
($)~~~($)
of Settlement ($)
(g)
(h)(i)
(j)
(I)(m)
230,026 127,156
63,963 049 042 164
972 419,421 248
941 947
898 310,567 310,567
286
246 400 11,630,08C 11,630,080
445,827 892 16E 892,166
40C 26,80C 26,800
81C 369 28E 369,286
391 437 887 437 887
782 37,692 267 652 305,344
984 138,467 138,467
245 526 83C 526,830
15,594 487 12,902,326 264 299 106 195,300 235,473 156 -974 015,269 367 653 187
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
PU~C~A~ED POWER ~Accou~t 555)( nc u Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term " means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Entergy-Koch Trading, loP.
Eugene Water & Electric Board
Eugene Water & Electric Board
Eurus Energy America
FPL Energy Power Marketing, Inc.
Falls Creek
Farmers Irrigation District
Fery, Loyd
Fillmore City
Franklin Co. Public Utilities District
Galesville Dam
Garland Canal
General Chemical Corporation
Georgetown Power
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
~I '"'I . CCOUR\~g~~) (Continued)
. "" .......
1ncludlng power exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column m, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l)No.
Received Delivered
\~~
\fl
of Settlement ($)
(g)
(h)(i)(m)
291 57E 13,239,631 13,239 637
15C 150
40,57C 949,S5C 949,550
118,98~249,59€249,598
68E 204 02E 204 028
031 231 829 512,336 744 168
20,53/287,945 840,161 128,106
266 11 ,525 525
182 19,68C 19,680
05~88,811 817
521 934 463 86E 527 799
64C 127 684 326,2Oi 453 891
2,44~40E 405
03~25E 50,255
15,594 487 902 326 264 299 106,195,300 235 473,156 974 015,269 367,653 187
FERC FORM NO.1 (ED. 12-90)Page 327.
This Re rt s:
(1) X An Original(2) A Resubmission
PURCHASED POWER lAccou(lt 555)(Includlng power excl'langes)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Glendale, City of
2 Grand Valley Power
3 Grant County Public Utility District
4 Grant County Public Utility District
5 Grant County Public Utility District
6 Grant County Public Utility District
7 Grant County Public Utility District
8 Grant County Public Utility District
9 Grant County Public Utility District
10 Grays Harbor Public Utility District
11 Grays Harbor Public Utility District
12 Heber Light & Power Company
13 Hermiston Generating Company, loP.
HermlstOn~~tj~g
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Actual Demand (MW)verage verage
Monthly NCP Deman Monthly CP Demand(e) (f)
Average
Monthly Billing
Demand (MW)
(d)
242 241 207
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliers system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column W, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)~~~
\fl of Settlement ($)
(g)
(h)(i)(m)
20,1,475,708
097
534,461 334,
755,711 172
36,580
152,246 134 942
14,453
400
225 229,865
800
146,146 545
315 315,215
074
866,33,795,599 48,293,391 890
15,594 487 902 326 13,264 299 106,195,300 235,473 156 974 015,269 367 653
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
PU~CHA~ED POWER ~Accou~t 555)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service , aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Hexcel IIIHorizon Milling LLC
Hum Wind
Hurricane, City of
IGI Resources, Inc.
Idaho Falls, City of
Idaho Falls, City of
Idaho Power Company
Idaho Power Company
Ingram Warm Springs Ranch
Intermountain Power Project
J. Aron & Company
Kennecott
Kennecott
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
This ~ort Is:(1) ~ An Original(2) A Resubmission
ccounncludln po er exchange)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGESMegaWatt Hours
Purchased MegaWatt Hours MegaWatt HoursReceived Delivered
~) (~
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
~~~
\f?
Demand Charges
($)
30,591
761
590,
893
336,
222,
106
457,
40,595,
336 301
15,594 487 902 326 13,264 299 106 195,300 235,473 156 974 015,269
FERC FORM NO.1 (ED. 12-90)Page 327.
LineTotal U+k+l) No.
of Settlement ($)
(m)
484
848
351
272
623,250
464 012
336,560
79,700
020 007
106,847
457 625
40,595,844
336,301
872,789
367 653,
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
. PU~CHA~ED POWER ~ACCOU')t 555)nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Lacomb Irrigation
Lake Siskiyou
Los Angeles Dept. of Water & Power
Los Angeles Dept. of Water & Power
Lucky, Paul
Magnesium Corporation of America
Marsh Valley Hydro & Electric Co.
Marsh Valley Hydro & Electric Co.
Middlefork Irrigation District
Mink Creek Hydro
Mirant Americas Energy Marketing
Mirant Americas Energy Marketing
Monsanto
Monsanto
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
is ~rt Is:(1) ~ An Original(2) A Resubmission
ccoun0 er exchan e )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
Year/Period of Report
End of 2004/04
Name of Respondent
PacifiCorp
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (50-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (50-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
5. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column W, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
~~~($)
of Settlement ($)
(g)
(h)(i)(I)(m)
242,270,500
356,665 009,366 063
40,44 903,025,
89,280,611 280,611
19,008
104 206 591 206 591
976
131 131 893
25,191,077 103,295,042
389,389,206
189,189 629
315,315,929
938
344
15,594 487 902 326 13,264 299 106 195 300 235,473,156 974 015,269 367 653,
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This I ort Is:Date of Report Year/Period of Report
PacifiCorp (1)X An Original (Mo, Da, Yr)End of 2004/04
(2)- A Resubmission 04/25/2005
PU~C~A~ED POWER hAccou~t 555)( nc u Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term " means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman(Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Morgan '~ity IIIMorgan S~anley Capital Group, Inc.
Morgan Stanley Capital Group, Inc.
Morgan Stanley Capital Group, Inc.100
Morgan Stanley Capital Group, Inc.
Mountain Energy
Municipal Energy Agency of Nebraska
Iii
Municipal Energy Agency of Nebraska
Nephi City
Nevada Power Company
Nevada Power Company
Nevada Power Company
Nicholson Sunnybar Ranch
North Fork Sprague 0.4
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
is ~ort Is:(1) ~ An Original(2) A Resubmission
ccounncludln po er exchange)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column W, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
($)~~~($)
of Settlement ($)
(g)
(h)(i)(I)(m)
577 ,273
18,395,395,640
56,740,000 080 820 000
526 115,598,116,488,135
827 895
340
12,466,466 184
676
28,125,125 670
12,459 523,236
66,280
705 175,213,051
15,594 487 12,902 326 13,264 299 106,195 300 235,473 156 974 015 269 367 653,
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04
(2) LJ A Resubmission 04/25/2005
PU~CHA~ED POWER ~Accou~t 555)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
NorthWestern Energy
Northern California Power Agency
Nucor Corporation
J. Power Company
ONEOK Energy Marketing & Trading Co.
Occidental Power Services, Inc.
Odell Creek
PPL Energy Plus, LLC
PPL Energy Plus, LLC
PPL Montana, LLC
PPL Montana, LLC
Pacific Gas & Electric Company
Pacific Northwest Generating Coop.
Pancheri, Inc.
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
This ~ort Is: Date of Report(1) L!SJ An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005ccount on Inunc udlng po er exchange)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGESMegaWatt Hours
Purchased MegaWatt Hours MegaWatt HoursReceived Delivered
(g)
(h) (i)
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
Demand Charges
($)(j)
575,
13,
86,
203,
973,52,
15,594,487 902 326 13,264,299 106,195,300 235,473,156 974 015,269
FERC FORM NO.1 (ED. 12-90)Page 327.
Total (j+k+l)
of Settlement ($)
(m)
723
227 052
932 000
837
668,779
575,957
16,286
86,250
203,166
244
974 065
542 313
648,272
231
Line
No.
367 653
This ~ort (1) ~ An Original(2) A Resubmission
PURCHASED POWER (Accou(1t 555)(Including power excl1anges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from translTlission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(8)
Statistical
Classifi-
cation
(b)
1 Panda Gila River
2 Panda Gila River
3 Payson City Corporation
Pinnacle West Capital Corporation
Pinnacle West Capital Corporation
Pinnacle West Capital Corporation
Portland General Electric Co.
Portland General Electric Co.
Portland General Electric Co.
10 Powerex
11 Powerex
12 Powerex
13 Preston City Hydro
14 Provo City
Total
FERC FORM NO.1 (ED. 12-90)
FERC Rate
Schedule or
Tariff Number
(c)
Actual Demand (MW)verage verage
Monthly NCP Deman Monthly CP Demand(e) (f)
Average
Monthly Billing
Demand (MW)
(d)
Page 326.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2004/04
(2) ~ A Resubmission 04/25/2005
, ...
nc
. r:.~!.v I;;;.)WEcCOUR\~g~~\ (liontlnued)udmg po er exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
B. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.
Received Delivered
($)~~~($)
of Settlement ($)
(g)
(h)(i)(I)(m)
85::295,017 295,017
110,02~742 03f 742 038
94C 940
48,80C 708,80C 708 800
54~118,118,075
10,07C 498,16C 498,160
19'840'
403,127
12,02~180,000
448,80C 19,865 804
89,49i 206,35E 206,359
12~97~975
679,94E 35,272 62E 35,272,626
25~102 09~102 095
189 531 531
594,487 902,326 264 299 106,195,300 235,473,156 974,015,269 367,653 18i
FERC FORM NO.1 (ED, 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04
(2) D A Resubmission 04/25/2005
PU~CHA~ED POWER ~Accou~t 555)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term " means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Public Service Company of Colorado
Public Service Company of Colorado
Public Service Company of New Mexico
Public Service Company of New Mexico
Public Service Company of New Mexico
Puget Sound Energy
Puget Sound Energy
RWE Trading Americas Inc.
Rainbow Energy Marketing
Rainbow Energy Marketing
Ralphs Ranch, Inc.
Redding, City of
Reliant Energy Services, Inc.
Riverside, City of
---
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
PI I.Ir
.. .
.... CCOUR\~g~~J (l;OntinUeC)I '" . '"' I
. (
nCfudmg pOwer exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total G+k+l)No.Received Delivered
~~~
\fl
of Settlement ($)
(g)
(h)(i)(m)
566 388,66-4 388,664
656,976 36,339 10E 339 108
134,400 923,55~923,552
192 32S 790 84~792 518
288,446 11,457 16C 506,608
125
192 155 560,444 592 496
39,40C 033,600 033,600
69€937 937
68C 746,360 746,360
29~20,968 968
941 153 77,153
22,57C 080 714 080 714
109 65,586 65,586
15,594,487 12,902 326 13,264 299 106,195 300 235,473,156 974 015,269 367 653,187
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) D A Resubmission 04/25/2005
~CH~ED POWER hAccou~t 555)nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Riverside, City of
Rocky Mountain Generation Coop.
Roush Hydro, Inc.
Sacramento Municipal Utility District
Sacramento Municipal Utility District
Salt River Project
Salt River Project
San Diego Gas & Electric
Santi am Water Control District
Seattle City Light
Seattle City Light
Seawest
Sempra Energy Resources 100
Sempra Energy Resources
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
This ~ort Is:(1) l2S..J An Original(2) 0 A Resubmission
ccoun
Inc udlng po er exchange)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service , asidentified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column m. energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered
($)
~t~
($)
of Settlement ($)
(g)
(h)(i)
(j)
(I)(m)
115,115,784
35,111,111
14,002
197 138,127 012
242,242,896
111,741 576,576,536
179,931 933,151
301 945,945,326
13,582 117 131 101
200
838,849 610
137 219,371
660 000 017 594 620
36,36,600
15,594 487 12,902,326 13,264,299 106,195,300 235,473,156 974 015,269 367 653,
FERC FORM NO.1 (ED. 12-90)Page 327.
his e ort s:(1) An Original(2) A Resubmission
PURCHASED POWER lAccou(lt 555)(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
--- ttJ~-forlntermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
1 Sempra t;:nergy Trading Corp.
2 Sempra Erergy Trading Corp.
Sierra Pacific Power Company
Sierra Pacific Power Company
Sierra Pacific Power Company
6 Simplot Phosphates, LLC
Simplot Phosphates, LLC
8 Slate Creek
9 Snohomish Public Utility District
10 Southern California Edison Company
11 Southern California Edison Company
12 Southwestern Public Service Company
13 Spanish Fork City
14 Springville City
Statistical
Classifi-
cation
(b)
Line
No.
Total
FERC FORM NO.1 (ED. 12-90)
FERC Rate
Schedule or
Tariff Number
(c)
Actual Demand (MW)verage verage
Monthly NCP Deman Monthly CP Demand(e) (f)
Average
Monthly Billing
Demand (MW)
(d)
1.8
Page 326.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
4. In column (c), identity the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total G+k+l)No.
Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
245
773,614 797
373
13,050
670,865
776,866
926
11,44 174,836 943,118,720
459 459 802
377,377 028
69,030 030,332
650
4,42
576
15,594,487 902 326 264 299 106,195,300 235,473,156 974 015,269 367 653,
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent
PacifiCorp
This ~rt Is:(1) ~An Original(2) A Resubmission
PURCHASED POWER (Accou(lt 555)(Including power excl'langes)
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints , must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing verage verage
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Deman
(a)(b)(c)(d)(e)(f)
1 Strawberry Electric Service District
2 Sunnyside Cogeneration Associates
3 Sunnyside Cogeneration Associates 52.51.45.4
4 Tacoma, City of
5 Tacoma, City of
6 Tesoro Refining and Marketing Co.
7 Thayn Ranch Hydro
8 Tractebel Energy Marketing, Inc.
9 TransAlta Energy Marketing Inc.
10 TransAlta Energy Marketing Inc.
11 TransAlta Energy Marketing Inc.
12 Tri-State Generation & Transmission
Tri-State Generation & Transmission
Tri-State Generation & Transmission
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
This ~ort Is:(1) ~ An Original(2) A Resubmission
ccountnc udlng po er exchange)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column m, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.Received Delivered
~~~($)
of Settlement ($)
(g)
(h)(i)(I)(m)
530
503
395,10,160 114 834,994 319
250
86,854 858,501
12,951 608 608,686
28,465 116 031
229,391 125 10,125,038
360,861 120,342 118,450,474
503,68,137 137 403
285,040 000 209 249,
33,128 128
630 630 723
15,594,487 902 326 264 299 106 195,300 235,473 156 974 015 269 367 653,
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
~CHA~ED POWER hAccou~t 555)nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RO service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi.Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Tucson Electric Power
Tucson Electric Power
UBS Warburg Energy LLC
Utah Assoc. Municipal Power Systems
Utah Assoc. Municipal Power Systems
Utah Municipal Power Agency
Utah Municipal Power Agency
Walla Walla, City of
Warm Springs Forest Products
Washington City
Western Area Power Administration
Western Area Power Administration
Western Area Power Administration
Whitney, A. C.
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04
(2) 0 A Resubmission 04/25/2005
~l )\Nt-M'J),CCOU
~\~B~~:' (liontinued)1 nCiudmg power exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliers system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column m, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total O+k+l)No.
Received Delivered
($)
~t~
($)
of Settlement ($)
(g)
(h)(i)(I)(m)
25,87~870,025 870 025
89f 167 88E 167 885
585.22E 667 73C 28,667,730
31E 184 801 184 801
09C 126 94C 126,940
78C 780
49E 1,495
49€133,905 1,424,761 558,672
51€51S
216
63,35€188,212,301
60~246,334 751
15,594 487 902 326 13,264 299 106,195,300 235,473,156 974 015,269 367 653,187
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) D A Resubmission 04/25/2005
PU~CH~ED POWER K"ecou~t 5 )5)
(nclu Ing power exe anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Williams Energy Market & Trading Co.
Yakima Tieton
Accrual True-up
Bookout Purchases'"
Bookout Purchases
Potential Liability
Trade Purchases
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04
(2) ~ A Resubmission 04/25/2005
IL-L . !"'..\-!.~ 8cr~~fCOUR\~g~~J (ContlnueeJ)... .... 11"\udmg po er exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RO purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column W, energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments , in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l)No.
Received Delivered
~~~($)
of Settlement ($)
(g)
(h)(i)(I)(m)
41 ,70E 096,064 096,064
61E 848 713,732 773,580
112,559
305,909 252
539,470,502
724 266
15,211 ,60~941 896
594 487 902 326 13,264 299 106 195 300 235,473,156 974 015,269 367 653,187
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
~CHA~ED POWER ~Accou~t 555)
nclu mg power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
as - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Power Exchanges
Anaheim, City of WSPP
Arizon Public Service Co 306
Ashland, City of 353
Avista Corp.366
Avista Corp.554
Basin Electric Power Cooperative
Black Hills Power & Light Company 246
Bonneville Power Adminstration 554
Bonneville Power Adminstration 368
Bonneville Power Adminstration 237
Bonneville Power Adminstration
Bonneville Power Adminstration 256
Bonneville Power Adminstration
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
This ~ort Is:(1) ~ An Original(2) A Resubmission
ccouncludlng po er exc ange
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier s system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
POWER EXCHANGESMegaWatt Hours
Purchased MegaWatt Hours MegaWatt HoursReceived Delivered
(g)
(h) (i)
Demand Charges
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
360
571 392
841
360
571 392
000
055
524
116
882
100 000
137
5,402
100,000
075
689
aS63'lna'J"""i.,""
15,594 487 12,902 326 13,264 299 106 195 300 1 ,235,473,156 974 015 269
FERC FORM NO.1 (ED. 12-90)Page 327.
LineTotal O+k+l) No.of Settlement ($)
(m)
811,
820
967,550
179,008
259
499
512
119,155,920
367 653,
Name of Respondent This (gprt Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
PU~CHA~ED POWER ~ccou~t 555)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average AveragecationTariff Number Demand (MW)Monthly NCP Deman(Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Bonneville Power Adminstration
Bonneville Power Adminstration 347
Chelan County PUD No.554
Clark Public Utilities 417
Colockum Transmission Company
Emerald Peoples Utility District 351
Eugene Water & Electric Board
Flathead Electric Cooperative
Grant County PUD No.554
Idaho Power Company 380~EX
Portland General Electric 554
Public Service Company of CO
Public Service Company of CO 319
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004104
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliers system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt HoursReceived Delivered(h) (i)
102,383
946 879
Demand Charges
COSTISETTLEMENT OF POWER
Energy Charges Other Charges
~~~
Line
Total O+k+l)No.of Settlement ($)
(m)
112,485
670 000
561 517
921
744
308,578
850,879
894
MegaWatt Hours
Purchased
104 924
968,599
18,103
122
727
960
347
268,235
588
175,547
611
10,285
268,363
435
20,785
226
85,259
223,681
639
174,248
73,789
15,594,487 902 326 13,264,299 106,195,300 235 473,974 015,269 367 653
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
PU~CHA~ED POWER hAccou~t 555)
(nclu Ing power exc anges
1. Report all power purchases made during the year. Also report exchanges of electricity (Le., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RO - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (Le., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service.The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service.Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit.The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
No.(Footnote Affiliations)Classifi-Schedule or Monthly Billing Average Average
cation Tariff Number Demand (MW)Monthly NCP Demam Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Redding, City of 364
Seattle City Light 554
Tri-State Gen & Trans 319
Utah Associated Muni. Pwr Systems
Warm Springs Power Enterprise
Western Area Power Administration
System Deviation
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
This ~ort Is:(1) ~ An Original(2) A Resubmission
ccou
nc udlng po er exc ange )
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the suppliers system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column 0), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (I). Explain in a footnote all components of the amount shown in column (I). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401 , line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401 , line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours
Purchased
(g)
POWER EXCHANGES
MegaWatt Hours MegaWatt HoursReceived Delivered(h) (i)
122 904
328,376
170 155
Demand Charges
COST/SETTLEMENT OF POWER
Energy Charges Other Charges
($) ($)
(k) (I)
Total O+k+l)of Settlement ($)
(m)
762
95,664
161 267
Line
No.
259
19,445
125,305
336,325
289 257
138
963
18,453
288,176
498 893
15,594 487 12,902 326 13,264 299 106,195,300 235,473,156 974 015 269 367 653
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent
PacifiCorp
This ~rt Is:(1) ~ An Original(2) A Resubmission
Date of Report(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
ccoun
(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
1 Basin Electric Power Cooperative
2 Basin Electric Power Cooperative
3 Basin Electric Power Cooperative
4 Black Hills Power & Light Company
5 Black Hills Power & Light Company
6 Black Hills Power & Light Company
7 Black Hills Power & Light Company
8 Black Hills Power & Light Company
Bonneville Power Administration
10 Bonneville Power Administration
11 Bonneville Power Administration
12 Bonneville Power Administration
13 Bonneville Power Administration
14 Bonneville Power Administration
15 Bonneville Power Administration
16 Bridger Valley Rural Elec. Assoc.
17 Cargill-Alliant, LLC
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Powder River Energy Corp.
Statistical
Classifi-
cation
(d)
Black Hills Power & Light Co
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04
(2) LI A Resubmission 04/25/2005
LJ!- 1=1 1-1 . I Hllill Y FQR U I Ht:H~ (P ccount ,,- ontlnued)
(Including transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and G) the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours Megawatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)
(g)
(h)(i)
OV-Yellowtail Sub Sheridan Sub
OV-Yellowtail Sub Sheridan Sub
136 Dave Johnston Sub
OV-887 92,887
OV-200 200
OV-Various Sheridan Sub
OV-Various Wyodak Sub
226 Wyodak Sub
237 Various Various 294
324 Lost Creek Hydro Various 278,267 278 267
256 Various Various 143 447,546 447,54E
299 Various Various 226 195,058 195 05E
OV-Green Sp. Hydro Alvey Sub
OV-Various Gazely Sub
OV-415
213 Blacksfork Sub
OV -985 277 985,27 I
902 309,031 309,031
FERC FORM NO.1 (ED. 12-90)Page 329
Blank Page
(Next Page is: 330)
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
Date of Report(Mo, Da, Yr)
04/25/2005
ccount
(Including transactions retfered to as 'wlieelin '
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17 , respectively.
11. Footnote entries and provide explanations following all required data.
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERSEnergy Charges (Other Charges)
($) ($)
(I) (m)
Total Revenues ($)
(k+l+m)
(n)
Ine
No.
395 141 395,141
039
400
401 476
650
857 778
413,100
199
092,894
312,276
6,447 884
905,043
444 816
117,011
2,423
976
848,067
401 476
650
857,778
413,100
907
018,770
6,447,884
1 ,725,373
437 400
35,981
848,067
32,090,468 13,601 050 175,320 46,866,838
FERC FORM NO.1 (ED. 12-90)Page 330
Name of Respondent
PacifiCorp
This ~ort Is:(1) ~An Original(2) A Resubmission
YearlPeriod of Report
End of 2004/04
Date of Report
(Mo, Da, Yr)
04/25/2005
ccount(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Cargill-Alliant, LLC
2 Coral Power
3 Conoco
4 Deseret Generation & Transmission
5 Deseret Generation & Transmission
6 Deseret Generation & Transmission
7 Eugene Water & Electric Board
Fall River Rural Electric Coop.
Flathead Electric Cooperative Inc.
10 Idaho Power Company
11 Idaho Power Company
12 Idaho Power Company
13 Idaho Power Company
14 Idaho Power Company
15 J. Aron & Company
16 Moon Lake Electric Association
17 Morgan Stanley Capital Group, Inc.
Marysville Hydro Partners
Western Area Power Admin
Nevada Power
Idaho Power Company
Flathead Electric Coop., Inc.
Idaho Power Company
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This (8Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
~!- EU:G I Hllill rQR U I I 1I:;:n~J~ ccount ontlnued)
(lncludinQ transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and m the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand MegawattRours MegaWatt Hours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(1)
(g)
(h)(i)
OV-441 550 441 55C
OV-465 41,465
OV-
280 Various Various
280 Various Various
OV-544 54~
OV-695 6ge
322 Targhee Sub Goshen Sub
OV-Yellowtail Sub Various
OV-Red Butte BorahlBrady
OV-377 085 377,085
OV-483,312 483 31~
257 Antelope Sub
203 Jim Bridger Sub
OV-975 97e
302 Duchesne Duchesne
OV-760 76C
902 309,031 309 031
FERC FORM NO.1 (ED. 12-90)Page 329.
. .
Blank Page
(Next Page is: 330.
ccoun
(Includin transactions reffered to as 'wlieelin '
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and m must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
This ~ort Is:(1) ~ An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004104Name of Respondent
PacifiCorp
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERSEnergy Charges (Other Charges)
($) ($)
(I) (m)
121 486
119,150
432
Total Revenues ($)
(k+l+m)
(n)
Ine
No.
858
059
121 486
119,150
432
543,659
133 841
858
059
151 308
49,195
455 625
042,875
484 396
73,824
284
694
22,844
660
222
151,308
650
455,625
042 875
484 396
694
844
51,660
32,090,468 13,601 ,050 175,320 46,866,838
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent
PacifiCorp
This ~ort Is:
(1 ) An Original(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004104
ccoun
(Including transactions referred to as 'wheeling
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, as - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
1 Morgan Stanley Capital Group, Inc.
Pacific Gas & Electric
Pacific Gas & Electric
12 Powerex
13 Powerex
14 Powerex
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
Portland General Electric
Portland General Electric
Portland General Electric
PPL Montana, LLC
Public S~rvice Company of CO
Public Se~ice Comp~ny of CO
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, De, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
I ..ut- j;;\ I-r . I HIl;1l Y FOR (,) I HcH~ ,(fJ ccount ontmued)(Including transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and m the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY LineSchedule of (Subsatation or Other (Substation or Other Demand Megawatt Hours lVfegaWatt riours No.Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)
(g)
(h)(i)
OV-142 846 142 84E
Malin Sub Indian Springs
298 Pinto Sub
OV-Wallula Sub Mid-155
OV-UINTAlPV/Evanston MPAC 125
OV-Exxon Meter Stat.H. Allen/Mona Sub
OV-561 500 561 50e
OV-55,800 55,80e
137 Dalreed Sub Dalreed Sub
372 Harrison Sub Harrison Sub
OV-Bonneville Pwr Ad Weed Jct. Sub
OV-416 636 416,63E
OV-631 112 631 11~
OV-46,073 07~
OV-128,400 128,40C
OV-138,700 138 70C
902 309 031 309 031
FERC FORM NO.1 (ED. 12-90)Page 329.
Blank Page
(Next Page is: 330.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004104
ccoun
(Includin transactions reffered to as 'wheelin '
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and m must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERSEnergy Charges (Other Charges)
($) ($)
(I) (m)
715,424
Total Revenues ($)
(k+l+m)
(n)
Ine
No.
829,051
029,435
267,344
375,825
571,198
944,000
829 051
029,435
267 344
375 825
461 848
237 500
429
972,000
025,000
151,875
715,424
237 500
451,527
972 000
025 000
151,875
140,008
151 875
299
260
140 008
151 875
944
32,090,468 13,601,050 175,320 46,866,838
FERC FORM NO.1 (ED. 12-90)Page 330.
Date of Report
(Mo, Da, Yr)
04/25/2005
ccount(Includin transactions referred to as 'wheelin '
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Name of Respondent
PacifiCorp
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
1 Rainbow Energy Marketing
2 San Diego Gas & Electric
3 Seawest Windpower, Inc.
4 Sempra Energy
5 Sempra Energy
6 Sheridan-Johnson Rur Elec. Assoc.
Sierra Pacific Power Company
Sierra Pacific Power Company
9 Southern California Edison Co.
10 Southern California Edison Co.
11 State of South Dakota
12 TransAlta Energy Marketing Inc.
13 TransAlta Energy Marketing Inc.
14 Tri-State Gen & Trans
15 Tri-State Gen & Trans
16 Tri-State Gen & Trans
17 Tri-State Gen & Trans
Line
No.
TOTAL
FERC FORM NO.1 (ED. 12-90)
Year/Period of Report
End of 2004104
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
Page 328.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2004/04
(2) 0 A Resubmission 04/25/2005
OF 1=1 H ., HIl,;I I Y FQR LJ 1 Ht:H:::; ,(/J ccount A(;.~lfr ontlnued)
(Including transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and m the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand MegaWatt Hours MegaWatt Hours No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)
(g)
(h)(i)
OV.18,282 18,28~
Malin Sub Indian Springs
OV-Foote Creek Sub
OV.12,244 12,244
OV-960 960
Buffalo Sub
OV-27,360 36C
OV.700 646 700 64E
Malin Sub Indian Springs
298 Pinto Sub
OV-Yellowtail Sub Wyodak Sub
OV-540 54C
OV.104 10~
OV-180 18C
123 Difficulty Sub
123 Riverton Sub
123 Thermopolis Sub
902 309,031 309,031
FERC FORM NO.1 (ED. 12-90)Page 329.
Blank Page
(Next Page is: 330.
Name of Respondent
PacifiCorp
This ~ort Is:(1) ~ An Original(2) A Resubmission
Year/Period of Report
End of 2004/04
Date of Report(Mo, Da, Yr)
04/25/2005ccount ontlnue
(Including transactions retfered to as 'wlieelin '
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and m must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERSEnergy Charges (Other Charges)
($) ($)
(I) (m)
78,901
Total Revenues ($)
(k+l+m)
(n)
Ine
No.
901
33,250
588,062
51,517
750
171
649
999,670
204 250
451 527
200
38,194
12,564
051
14,904
164
328
204 250
429,
200
541
38,194
12,564
051
32,090,468 13,601,050 175,320 46,866,838
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent
PacifiCorp
Date of Report
(Mo, Oa, Yr)
04/25/2005
Year/Period of Report
End of 2004104
ccount
(Includin transactions referred to as 'wheelin '
1. Report all transmission of electricity, Le., wheeling, provided for other electric utilities, cooperatives , other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
1 Tri-State Gen & Trans
2 Tri-State Gen & Trans
United States Bureau of Rec.
United States Bureau of Rec.
5 Utah Associated Municipal Power
6 Utah Associated Municipal Power
7 Utah Municipal Power Agency
8 Utah Municipal Power Agency
9 Warm Springs Power Enterprises
10 Western Area Power Administration
11 Western Area Power Administration
12 Western Area Power Administration
13 Western Area Power Administration
14 Western Area Power Administration
15 Western Area Power Administration
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
Bonneville Power Admin
Bonneville Power Admin
Crooked River Irrigation District
United States Bureau of Rec
Utah Assoc. Municipal Power
Utah Assoc. Municipal Power
Utah Municipal Power Agency
Weber Basin Project Western Area Power Admin
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2004/04
(2) 0 A Resubmission 04/25/2005
OF ELEGI HI\;I I Y FQR OTHERS ,(/J ccount ontlnued)
(Including transactions reffered to as 'wheeling
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path
, "
point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation , or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract.Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and m the total megawatthours received and delivered.
FERC Rate Point of Receipt Point of Delivery Billing TRANSFER OF ENERGY Line
Schedule of (Subsatation or Other (Substation or Other Demand Megawatt Hours MegaWatt Hours No.
Tariff Number Designation)Designation)(MW)Received Delivered
(e)(f)
(g)
(h)(i)
123 Platte Sub
123 Various Various
Franklin Sub Various 500 50C
Redmond Sub Various
297 Various Various
OV-858 85f
279 Various Various
OV-
OV-
262 Various Various 327
OV-Wyoming Various Wyoming Various 178 17, 17f
OV-Wyoming Dist Wyoming Dist
331 Casper Sub
330 Thermopolis Sub
286 Various Various
90~309,031 309,031
FERC FORM NO.1 (ED. 12-90)Page 329.
Blank Page
(Next Page is: 330.
Name of Respondent
PacifiCorp
This ~ort Is:(1) ~An Original(2) A Resubmission
Year/Period of Report
End of 2004/04
Date of Report
(Mo, Da, Yr)
04/25/2005
ccount
(Including transactions reffered to as 'wtieelin I
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and G) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401 , Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
Demand Charges
($)
(k)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERSEnergy Charges (Other Charges)
($) ($)
(I) (m)
Total Revenues ($)
(k+l+m)
(n)
Ine
No.
30,004
164
54,497
178
417
243,533
4,408
547,340
119,700
783 958
100,320
334
628
10,164
084
000
597
470 663
440,000
119,700
781 958
40,084
32,090,468 13,601,050 175,320 46,866,838
FERC FORM NO.1 (ED. 12-90)Page 330.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
TRANS~ ISSION OF ELECTRICITY BY OTHE ~S (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, Le. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERG'Y EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawan-lJemana !:nergy lJtner Total Cost of
HouTs Hours Char?eS Charres Char?eS Trans~isSlonAuthority (Footnote Affiliations)Classification Received Delivered
(a)(b)(c)(d)(e)(f)
(g)
1 Arizona Pub. Service Co 316 66,316 998 974
Arizona Pub. Service Co LFP 151,500 151,500 924 960 924 960
3 Arizona Pub. Service Co 15,790 15,790 966 53,966
Arizona Pub. Service Co 628
5 Arizona Pub. Service Co SFP 340,987 340,987 743,617 743,617
6 Avista Corp FNS 725 256 305,102 305,102
7 Avista Corp 127,609 127 609 356,866 356,866
8 Big Horn Aur Elec. Coop 161
9 Big Horn Aur Elec. Coop 788i~-
Blanding City 494 494 962 962
Blanding City LFP 852 852 109 109
Bonneville Power Admin 430 169
Bonneville Power Admin FNS 427 046 772,882
Bonneville Power Admin LFP 641 641 239,350 954 245,304
Bonneville Power Admin 159,804 159,804
Bonneville Power Admin 10,181 789 10,246,188 234,791 573,089585,805 52.4~a
TOTAL 141 411 277 611 798,593 565 602 16,580 233 76,944,428
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
TRANS" ISSION OF ELECTRICITY BY OTHE ~S (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, Le. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities , and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OlF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawatt:!::J.emana !=;nergy utner Total Cost of
HoUTS Hours charfes charfes charfes Trans~sslonAuthority (Footnote Affiliations)Classification Received Delivered
(a)(b)(c)(d)(e)(f)
(g)
1 Bonneville Power Admin SFP 514 514 176,064 176,064
2 California ISO 542 ~~i:-283,442
3 California ISO 329,069 329,069 884 263 884,263
4 California ISO 794,823
5 Colorado River Cornrn.891 891
6 Deseret Gen & Trans SFP 126 126 187,970 187,970
Flowell Electric Assoc.137 137 104 104
Flowell Electric Assoc.LFP 177 177 247 247
9 Hermiston Generating Co 11\1 150,919919
Idaho Power Company 225 225 536 137 674
Idaho Power Company FNS 870 870
Idaho Power Company 758,821 758,821 481,425 45,643 527,068
Idaho Power Company ~:C'820,5312(),~f:
Idaho Power Company SFP 220,492 255,617 492,113 492 113
LA Dept. of Water & Pwr 26,026
LA Dept. of Water & Pwr SFP 401 401 90,774 90,774
TOTAL 141,411 14,277,611 798,593 565,602 16,580,233 944,428
FERC FORM NO. 1/3-0 (REV. 02-04)Page 332.
Year/Period of Report
End of 2004/04This ~rt Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
TRANS ISSION OF ELECTRICITY BY OTHE S (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, Le. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities , qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OlF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and as - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Name of Respondent
PacifiCorp
LineNo. Name of Company or Public
Authority (Footnote Affiliations)(a)
1 MAPPCOR
2 MAPPCOR
3 Monsanto
4 Moon Lake Elec. Assoc.
5 Moon Lake Elec. Assoc.
6 Morgan City
7 Navajo Tribal Util Auth
8 Nevada Power Company
9 Nevada Power Company
10 Nevada Power Company
11 Nevada Power Company
12 NorthWestern Energy
13 NorthWestern Energy
14 NorthWestern Energy
15 NorthWestern Energy
16 Portland General Elec.
TOTAL
FERC FORM NO.1/3-Q (REV. 02-04)
Statistical
Classification
(b)
FNS
SFP
SFP
TRANSFER OF ENERGagawatt- agawa -!iouTs HoursReceived Delivered(c) (d)
22,433 22,433
38,023 38,023
076 076
28,173 28,173
594 74,298
462 462
141 411 14,277,611
Page 332.
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHEReman nergy er Total Cost ofCharges Charges Charges Trans iSSion
($) ($) ($)
ffl
953
753
486 000
188
85,156
735
344
926
126,599
060
209,604
129,268
145,537
739,082
353,574
487
368
126,599
735
209,604
145 537
353,574
487
798 593 565,602 16,580,233 76,944,428
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo. Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
TRANS~ ISSION OF ELECTRICITY BY OTHE ~S (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm TransmIssion
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERG'I EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No.Name of Company or Public Statistical Magawatt-Magawan-l,Jemana !:nergy (Jtner Total Cost of
liou,s liours Charres Charres Charres Trans~lssion
Authority (Footnote Affiliations)Classification Received Delivered
(a)(b)(c)(d)(e)(1)
1 Portland General Elec.770,583 771,883 143,401
Public Service Co of CO LFP 106,342 116,517 800 827 800,827
Public Service Co of NM
Public Service Co of NM 693
Public Service Co of NM SFP 292 40,292 76,825 76,a25
6 Puget Sound Energy 609 609 16,330 330
7 Puget Sound Energy
8 San River Project 126 126 480 480
9 Salt River Project SFP 750 750 848 848
Sierra Pacific Power Co 340 340 698
Sierra Pacific Power Co 70,496 70,496 110,373 110,373
Sierra Pacific Power Co 93,966
Snohomish PUD No.808 808 18,742 742
Springfield Util Board 12,980 12,980
Surprise Valley Elec.10,993
Tacoma, City of 124 124
TOTAL 14,141,411 14,277,611 58,798,593 565,602 16,580,233 944,428
FERC FORM NO. 1/3-0 (REV. 02-04)Page 332.
Name of Respondent This &rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) D A Resubmission 04/25/2005
TRANSf\ ISSION OF ELECTRICITY BY OTHE ~S (Account 565)
(Including transactions referred to as "wheeling
1. Report all transmission, Le. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, lFP - Long-Term Firm Point-to-Point Transmission Reservations. OlF - Other.
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER,
No.Name of Company or Public Statistical Magawatt-Magawan-!,Jemana ~nergy ~mer Total Cost ofHoursHoursCharresCharresCharresTrans~issionAuthority (Footnote Affiliations)Classification Received Delivered(a)(b)(c)(d)(e)(1)
(g)
1 Tri-State Gen & Trans LFP 245 517 262,483 683,727 683 727
Tri-State Gen & Trans 032 032 516 15,516
3 Tucson Electric Power
Tucson Electric Power
5 Utah Assoc Muni Pwr Sys LFP 324
6 Utah Assoc Muni Pwr Sys SFP 199,500 199,500
7 Western Area Pwr Admin 205 205 582 608
8 Western Area Pwr Admin FNS 522 622 522,622
9 Western Area Pwr Admin LFP 360 831 360 831 535 000 535 000
Western Area Pwr Admin 245 245 832 832
Western Area Pwr Admin 949 457 013
Western Area Pwr Admin SFP 584 584 055 055
Accrual True-up 483,576
TOTAL 14,141,411 277 611 58,798,593 565,602 16,580,233 76,944,428
FERC FORM NO. 1/3-0 (REV. 02-04)Page 332.
Blank Page
(Next Page is: 335)
Name of Respondent ThIS ~rt Is:Date of Rep'ort Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) A Resubmission 04/25/2005
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line Descri
ftion
Amount
No.(b)
Industry Association Dues 848,881
Nuclear Power Research Expenses
Other Experimental and General Research Expenses
Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 656,466
Oth Expn ;:.=5,000 show purpose, recipient, amount. Group if c: $5,000
Bank Charges and Fees
Bank One 469
US Bank 039
Wachovia Bank 223,446
Wells Fargo Bank 810
Other 341
Community & Economic Development
Box Elder County Treasurer 10,000
Cache Chamber of Commerce 000
Cedar City Corp 000
City of Montpelier 000
Economic Development for Central Oregon 000
Juab County Treasurer 000
Klamath County Economic Development 300
Oregon Economic Development Association 000
Pleasant Grove City 500
Portland Chamber of Commerce 15,000
Portland Development Commission 10,000
Redmond Economic Development 000
Rural Development Initatives Inc 000
Sevier County Treasurer 750
South Coastal Development Council 10,000
Utah Center for Rural Life 000
Wayne Brown Institute 10,000
Yakima County Development 000
Utah Defense Alliance 25,000
Utah Div of Parks & Recreation 000
City of Malad 10,000
Other 43,465
Corporate Memberships and Subscriptions
American Legislative Exchange 000
Cambridge Energy Research Associates 500
Energy Industry CBT Alliance 000
Green Strategies Inc 12,500
North American Energy 10,000
Northwest Power Quality Service 10,000
Corporate Memberships and Subscriptions - Continued
TOTAL 41,233,447
FERC FORM NO.1 (ED. 12-94)Page 335
Name of Respondent This ~ort Is:Date Qf Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) A Resubmission 04/25/2005
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line Descri)tion Amount
No.(b)
Operations Mgmt Roundtable 500
Pacific NW Utilities Conference 51,605
Portland Business Alliance 530
Rocky Mountain Electrical League 15,000
Salt Lake Area Chamber of Commerce 30,255
Sunnyside Inc 000
Utah Foundation 22,500
Utah Hispanic Chamber of Commerce 000
Utah Manufacturers Association 000
Western Electricity Coordinating Council 407,754
Western Energy Institute 47,500
Wyoming Business Alliance 000
Wyoming Taxpayers Association 950
Intermountain' Electrical Assoc 15,000
Other 82,433
Directors Fees - Regional Advisory Boards 355,981
General
1997 Software Write-Off UT Reg. Asset Amortization 385,773
1999 Software Write-Off UT Reg. Asset Amortization 275 267
98 Early Retirement - OR Reg. Asset Amortization 676,947
Adams Business Media Inc 500
Cascade Direct Inc 005
FY 05 Amort Exp/Rev -ID Tax Pymt Reg. Asset Amort 002 681
Glenrock Mine UT 1998 Case Reg Asset Amortization 152 774
Glenrock Mine UT Stipulat. Reg Asset Amortization 149 625
Nature Conservancy 000
Noell Kempf Reg. Asset Amortization 465
P&M Strike Reg. Asset Amortization 299,449
Scottish Power UK Mgmt Fee 10,528,651
Transition Plan Reg. Asset Amortization 15,485,311
Transition Team Costs - UT Reg. Asset Amortization 364,428
UT Amortization - Deferred Pension Reg Asset Amort 159 014
Write-off Misc Project Costs 873
Y2K Expenses OR Reg. Asset Amortization 53,822
Other 36,993
TOTAL 233,447
FERC FORM NO.1 (ED. 12-94)Page 335.
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2)D A Resubmission 04/25/2005
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
(Except amortization of aquisition adjustments)
1. Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant
included in any sub-account used.
In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
Depreciation Amortization of
Line ~reCiation Expense for Asset Limited Term Amortization of
No.Functional Classification xpense Retirement Costs Electric Plant Other Electric Total
(Account 403)(Account 403.(Account 404)Plant (Acc 405)
(a)(b)(c)(d)(e)(f)
1 Intangible Plant 49,856 768 119,178 50,975 946
2 Steam Production Plant 133,386,063 133,386,063
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 601,415 535 629 950
5 Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 646,346 098 651,444
7 Transmission Plant 547 191 547 191
8 Distribution Plant 116,124 087 116 124 087
9 General Plant 37,146,975 521 419 38,668,394
Common\Plant-Electric
TOTAL ilPji~i~~51,411,820 119,178 412 983,075
--.
B. Basis for Amortization Charges
The amortization of Limited-Term Electric Plant is based on straight-line amortization over the life of the asset.
The amortization of Other Electric Plant consists of costs associated with the merger of PacifiCorp and Utah Power & Light Company. Amortization is
straight-line over a 15 year period.
FERC FORM NO.1 (REV. 12-03)Page 336
Blank Page
(Next Page is: 350)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) An Original (Mo, Da, Yr)End of 2004/04
(2) Fi A Resubmission 04/25/2005
REGULA TORY COMMISSION EXPEN ES
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current years amortization of amounts
deferred in previous years.
Line Description Assessed by Expenses Total TIeferred
No.(Furnish name of regulatory commission or body the Regulatory Expense for in Account
Commission Current Year 18~.
docket or case number and a description of the case)Utility (b) + (c)Beginning 0 Year
(a)(b)(c)(d)(e)
Before the Public Service Commission of Utah:
Annual Fee 924 467 924,467
Before the Public Utility Commission of
Oregon:
Annual Fee 368 525 368,525
Before the Public Service Commission of
Wyoming:
Annual Fee 884 328 884,328
Other State Regulatory Expenses 837 837
Before the Washington Utilities and
Transportation Commission:
Annual Fee 378,079 378,079
Before the Idaho Public Utilities Commission:
Annual Fee 278 991 278 991
Before the Public Utilities Commission of
California:
Annual Fee 162 123 162 123
Before the Federal Energy Regulatory
Commission:
Annual Fee 234 861 234 861
Deferred Regulatory Commission Expense
TOTAL 231 374 837 233 211 000
FERC FORM NO.1 (ED. 12-96)Page 350
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
REGULATORY COMMISSION EXPENSE~ (Continued)
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to Contra Amount Deferred in Line
Department Amount Account 182.Account Account 182.No.No.End of Year
(f)
(g)
(h)(k)(I)
Electric 928 924 467
Electric 928 368,525
Electric 928 884 328
Electric 928 837
Electric 928 378,079
Electric 928 278,991
Electric 928 162,123
Electric 928 234,861
233,211
FERC FORM NO.1 (ED. 12-96)Page 351
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D &
D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(ldentify
recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of research, development, and demonstration in Uniform System of Accounts).
2. Indicate in column (a) the applicable classification, as shown below:
Classifications:
A. Electric R, D & D Performed Internally:(3) Transmission
(1) Generation a. Overhead
a. hydroelectric b. Underground
i. Recreation fish and wildlife (4) Distribution
ii Other hydroelectric (5) Environment (other than equipment)
b. Fossil-fuel steam (6) Other (Classify and include items in excess of $5,000.
c. Internal combustion or gas turbine (7) Total Cost Incurred
d. Nuclear B. Electric, R, D & D Performed Externally:
e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric
1. Siting and heat rejection Power Research Institute
Line Classification Description
No.(a)(b)
A. Electric R, D & D performed internally
(1) Generation
b. Fossil-fuel steam
Hunter Farm - Water balance study
Hunter Farm - Evapotranspiration study
Huntington Farm - Water balance study
Huntington Farm - Evapotranspiration Study
Huntington Farm - Saline Waste Water Study
(7) Total Cost Incurred
B. Electric R, D & D performed externally None
FERC FORM NO.1 (ED. 12-87)Page 352
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
(2) Research Support to Edison Electric Institute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Classify)
(5) Total Cost Incurred
3. Include in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $5 000 or more
briefly describing the specific area of R, D & D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.
Group items under $5 000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D & D
activity.
4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year,
listing Account 107, Construction Work in Progress, first. Show in column (1) the amounts related to the account charged in column (e)
5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research
Development, and Demonstration Expenditures, Outstanding at the end of the year.
6. If costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (1) with such amounts identified by
Est."
7. Report separately research and related testing facilities operated by the respondent.
Costs Incurred Internally Costs Incurred Externally AMOUNTS CHARGED IN CURRENT YEAR Unamortized Line
curre
fc~ Year Current Year Account Amount Accumulation No.
(d)(e)(1)
(g)
354 506 28,354
20,869 506 20,869
16,491 506 16,491
642 506 642
350 506 350
114 706 114 706
FERC FORM NO.1 (ED. 12-87)Page 353
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) A Resubmission 04/25/2005
DISTRIBUTION OF SALARIES AND AGES
Report below the distribution of total salaries and wage~ for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
(a)
568,877
804 963
918 698
177 043
792 237
Line
No.
Classification Direct PayrollDistribution Total
Electric
Operation
Production
Transmission
Distribution
Customer Accounts
Customer Service and Informational
Sales
Administrative and General
10 TOTAL Operation (Enter Total of lines 3 thru 9)
11 Maintenance
12 Production
13 Transmission
14 Distribution
15 Administrative and General
16 TOTAL Maint. (Total of lines 12 thru 15)
17 Total Operation and Maintenance
18 Production (Enter Total of lines 3 and 12)
19 Transmission (Enter Total of lines 4 and 13)
20 Distribution (Enter Total of lines 5 and 14)
21 Customer Accounts (Transcribe from line 6)
22 Customer Service and Informational (Transcribe from line 7)
23 Sales (Transcribe from line 8)
24 Administrative and General (Enter Total of lines 9 and 15)
25 TOTAL Oper. and Maint. (Total of lines 18 thru 24)
26 Gas
27 Operation
28 Production-Manufactured Gas
29 Production-Nato Gas (Including Expl. and Dev.
30 Other Gas Supply
31 Storage, LNG Terminaling and Processing
32 Transmission
33 Distribution
34 Customer Accounts
35 Customer Service and Informational
36 Sales
37 Administrative and General
38 TOTAL Operation (Enter Total of lines 28 thru 37)
39 Maintenance
40 Production-Manufactured Gas
41 Production-Natural Gas
42 Other Gas Supply
43 Storage, LNG Terminaling and Processing
44 Transmission
45 Distribution
46 Administrative and General
47 TOTAL Maint. (Enter Total of lines 40 thru 46)
45,043 164
368,793
213 623
893,242
518,822
123 612,041
13,173,756
89,132,321
177,043
792,237
FERC FORM NO.1 (ED. 12-88)Page 354
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
DIST ,IIBUTION OF SALARIES AND WAGE S (Continued)
Line Classification Direct Payroll Allocation o!TotalDistributionPayroll charged for
No.Clearin~ Accounts
(a)(b)(d)
Total Operation and Maintenance
Production-Manufactured Gas (Enter Total of lines 28 and 40)
Production-Natural Gas (Including Expl. and Dev.) (Total lines 29,
Other Gas Supply (Enter Total of lines 30 and 42)
Storage, LNG Terminaling and Processing (Total of lines 31 thru
Transmission (Lines 32 and 44)
Distribution (Lines 33 and 45)
Customer Accounts (Line 34)
Customer Service and Informational (Line 35)
Sales (Line 36)
Administrative and General (Lines 37 and 46)
TOTAL Operation and Maint. (Total of lines 49 thru 58)
Other Utility Departments
Operation and Maintenance
TOTAL All Utility Dept. (Total of lines 25, 59, and 61)352,297,426 352,297,426
Utility Plant
Construction (By Utility Departments)
Electric Plant 130,819,997 130,819,997
Gas Plant
Other (provide details in footnote):
TOTAL Construction (Total of lines 65 thru 67)130,819,997 130 819,997
Plant Removal (By Utility Departments)
Electric Plant
Gas Plant
Other (provide details in footnote):
TOTAL Plant Removal (Total of lines 70 thru 72)
Other Accounts (Specify, provide details in footnote):
Other Income and Deductions
Other Income 124 201 124 201
Other Income Deductions 561 490 561 490
Fuel Stock 22,092 789 092,789
Nonutility 921 366 921 366
TOTAL Other Accounts 20,576,866 20,576,866
TOTAL SALARIES AND WAGES 503,694 289 503,694 289
FERC FORM NO.1 (ED. 12-88)Page 355
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04
(2) D A Resubmission 04/25/2005
PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
In columns for usage, report usage-related billing determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year.
(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year.
(5) On lines 5 and 6 , columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary services purchased or sold during
the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
Amount Purchased for the Year Amount Sold for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant
Unit of Unit of
Line Type of Ancillary Service Number of Units Measure Dollars Number of Units Measure Dollars
No.(a)(b)(c)(d)(e)(f)
(g)
1 Scheduling, System Control and Dispatch
2 Reactive Supply and Voltage
3 Regulation and Frequency Response 53,092 050 MWH 8,494 728 53,183 597 MWH 509 376
Energy Imbalance 25,060 MWH 860 125
5 Operating Reserve - Spinning 48,538,649 MWH 701 404 916 895 MWH 440,515
Operating Reserve. Supplement 48,538,649 MWH 701,404 50,225 559 MWH 18,242,600
Other
8 Total (Lines 1 thru 7)150,169 348 43,897,536 154 351 111 052 616
FERC FORM NO.1 (New 2-04)Page 398
Name of Respondent This I e IOrt Is:Date of Report Year/Period of Report
PacifiCorp (1)X An Original (Mo, Da, Yr)End of 2004/04
(2)= A Resubmission 04/25/2005
M )NTHL Y TRANSMISSION SYSTEM PEAK LOAD
(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically
integrated, furnish the required information for each non-integrated system.
(2) Report on Column (b) by month the transmission system s peak load.
(3) Report on Columns (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through m by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for
the definition of each statistical classification.
NAME OF SYSTEM:
Line Monthly Peak Day of Hour of Firm Network Firm Network Long-Term Firm Other Long-Short-Term Firm Other
No.Month MW - Total Monthly Monthly Service tor Selt Service for Point-to-point Term Firm Point-to-point Service
Peak Peak Others Reservations Service Reservation
(a)(b)(c)(d)(e)(f)
(g)
(f)(f)(f)
1 January 12,4m 1900 033 907 3,413
2 February 800 599 841 413 524
3 March 731 800 010 764 3,413 544
4 Total tor Quarter 36,511 642 512 10,239 118
5 April 86.1000 500 654 194 516
6 May 11,42:1600 856 826 194 546
June 14,27~1700 024 028 891 333
8 Total tor Quarter 380 508 279 395
9 July 14,22C 1600 628 889 891 812
August 885 1600 8,473 968 891 553
September 784 1600 632 898 979 275
Total for Quarter 733 755 761 640
October 11,931 800 906 700 979 346
November 12,865 1800 943 940 343 639
December 965 926 158 455
Total for Quarter 22,814 566 10,480 1,440
Total for Year to
~~.~.
FERC FORM NO. 1/3-0 (NEW. 07-04)Page 400
~ Name of Respondent
?acifiCorp
This 13!E'0rt Is:(1) ~ An Original(2) A Resubmission
ELECTRIC ENERGY ACCOU T
Date of Report
(Mo, Da, Yr)
04/25/2005
YearlPeriod of Report
End of 2004104
Line
No.
Item
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
(a)
1 SOURCES OF ENERGY
2 Generation (Excluding Station Use):
3 Steam
4 Nuclear
5 Hydro-Conventional
6 Hydro-Pumped Storage
7 Other
8 Less Energy for Pumping
9 Net Generation (Enter Total of lines 3
through 8)
10 Purchases
11 Power Exchanges:
12 Received
13 Delivered
14 Net Exchanges (Line 12 minus line 13)
15 Transmission For Other (Wheeling)
16 Received
17 Delivered
18 Net Transmission for Other (Line 16 minus
line 17)
19 Transmission By Others Losses
20 TOTAL (Enter Total of lines 9, 10,
and 19)
FERC FORM NO.1 (ED. 12-90)
MegaWatt Hours
(b)
309,031
309,031
Page 401 a
Line
No.
Item
(a)
21 DISPOSITION OF ENERGY
22 Sales to Ultimate Consumers (Including
Interdepartmental Sales)
23 Requirements Sales for Resale (See
instruction 4, page 311.
24 Non-Requirements Sales for Resale (See
instruction 4, page 311.
25 Energy Furnished Without Charge
26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
27 Total Energy Losses
28 TOTAL (Enter Total of Lines 22 Through
27) (MUST EOUAL LINE 20)
MegaWatt Hours
(b)
816,147
201 494
155,486
119 628
741 391
66,034 146
his ~rt Is:(1) ~An Original(2) A Resubmission
MONTHLY PEAKS AND OUTPUT
(1) Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required
information for each non- integrated system.
(2) Report on line 2 by month the system s output in Megawatt hours for each month.
(3) Report on line 3 by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
(4) Report on line 4 by month the system s monthly maximum megawatt load (60 minute integration) associated with the system.
(5) Report on lines 5 and 6 the specified information for each monthly peak load reported on line 4.
Date of Report
(Mo, Da, Yr)
04/25/2005
Year/Period of Report
End of 2004/04
Name of Respondent
PacifiCorp
NAME OF SYSTEM:
Line Monthly Non-Requirments MONTHLY PEAKSales for Resale &No.Month Total Monthly Energy Associated Losses Megawatts (See Instr. 4)Day of Month Hour
(a)(b)(c)(d)(e)(f)
29 January 821 052,611 069 1800 PST
30 February 195,209 102,690 599 0800 PST
31 March 5,471 793 274 714 010 0800 PST
32 April 738,631 814,827 518 0900 PST
May 967 567 848 325 856 1600 PDT
34 June 618,370 1 ,198 102 024 1700 PDT
35 July 038 070 763 628 1600 PDT
36 August 763,096 067,307 8,473 1600 PDT
September 226 479 155 349 632 1600 PDT
38 October 551 633 1 ,363,442 906 0800 PST
39 November 585,923 169 386 943 1800 PST
40 December 055,517 1 ,243 350 965 1800 PST
TOTAL 66,034 146 155 486
FERC FORM NO.1 (ED. 12-90)Page 401 b
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2004/04(2)D A Resubmission 04/25/2005 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operated
as a joint facility.4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant
~~1f~!~~~~!!!I!!No.Name: Carbon Name:
(a)(b)
Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam
Type of Constr (Conventional , Outdoor, Boiler, etc)Outdoor Boiler Full Outdoor
Year Originally Constructed 1954 1981
Year Last Unit was Installed 1957 1981
Total Installed Cap (Max Gen Name Plate Ratings-MW)188.414.
Net Peak Demand on Plant - MW (60 minutes)174 380
Plant Hours Connected to Load 8772 6914
Net Continuous Plant Capability (Megawatts)
When Not Limited by Condenser Water 172 380
When Limited by Condenser Water
Average Number of Employees
Net Generation, Exclusive of Plant Use - KWh 1135083000 2329937000
Cost of Plant: Land and Land Rights 956546 1231557
Structures and Improvements 11578139 46281686
Equipment Costs 73322778 323871764
Asset Retirement Costs
Total Cost 85857463 371385007
Cost per KW of Installed Capacity (line 17/5) Including 455.1392 897.0652
Production Expenses: Oper, Supv, & Engr 133906 1411609
Fuel 11442174 40557766
Coolants and Water (Nuclear Plants Only)
Steam Expenses 682262 2136057
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses 917382 1058448
Misc Steam (or Nuclear) Power Expenses 5311683 641989
Rents 40453 26492
Allowances
Maintenance Supervision and Engineering 2380460
Maintenance of Structures 492808 781662
Maintenance of Boiler (or reactor) Plant 4292805 7672009
Maintenance of Electric Plant 2548794 2723384
Maintenance of Misc Steam (or Nuclear) Plant 506026 2254321
Total Production Expenses 26368293 61644197
Expenses per Net KWh 0232 0265
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Oil Composite Coal Oil Composite
Unit (Coal-tons/Oil-barreVGas-mcf/N uclear -ind icate)Tons Barrels Tons Barrels
Quantity (Units) of Fuel Burned 559628 3564 1293004 4929
Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)11841 140000 9761 136800
Avg Cost of Fuellunit, as Delvd to.b. during year 19.951 52.190 000 30.347 48.552 000
Average Cost of Fuel per Unit Burned 20.114 52.190 000 31.182 48.552 000
Average Cost of Fuel Bumed per Million BTU 849 876 862 597 450 605
Average Cost of Fuel Burned per KWh Net Gen 010 000 010 017 000 017
Average BTU per KWh Net Generation 11675.587 18.465 11694.051 10833.782 12.155 10845.937
FERC FORM NO.1 (REV. 12-03)Page 402
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)
End of 2004/04(2)0 A Resubmission 04/25/2005
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32
, "
Maintenance of Electric Plant" Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plantPlant Plant Plant Line
Name:Dave Johnston No.
(f)
Steam Steam Steam
Conventional Outdoor Boiler Semi-Outdoor
1984 1979 1959
1986 1980 1972
155.172.816.
148 165 779
8717 8783 8784
148 165 762
188
1073325000 1296865000 5824643000
1291268 137086 10417290
56410315 35264290 48237859
149441269 125826417 352305858
57752 6172882
207200604 161227793 417133889
1331.5378 936.6629 510.7116
21728 213922 305193
7266743 14670922 36943321
759910 907128 210184
39461 385218 37229
1187070 2120486 12430434
12004 7873 4857
208758 441730 570
244129 121366 2012260
2257655 2175505 10337182
213907 1280507 5168676
345357 395133 1203100
12556722 22719790 68642152
0117 0175 0118
Coal Oil Composite Coal Gas Composite Coal Oil Composite
Tons Barrels Tons MCF Tons Barrels
680400 2135 634864 12090 3827412 7543
8558 140000 10167 1117 8316 140000
10.302 51.307 000 22.009 000 000 426 48.647 000
10.519 51.307 000 23.002 610 000 556 48.647 000
615 726 623 137 896 130 575 273 580
007 000 007 011 000 011 006 000 006
10850.142 11 .697 10861.840 9953.772 58.365 10012.137 10929.331 614 10936.945
FERC FORM NO.1 (REV. 12-03)Page 403
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2004/04(2) D A Resubmission 04/25/2005 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate rating) of 25 000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operated
as a joint facility.4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant fumish only the composite heat rate for all fuels burned.
Line Item
No.Name: Name:
(a)
Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam
Type of Constr (Conventional, Outdoor, Boiler, etc)Outdoor Boiler Outdoor Boiler
Year Originally Constructed 1965 1978
Year Last Unit was Installed 1976 1978
Total Installed Cap (Max Gen Name Plate Ratings-MW)81.443.
Net Peak Demand on Plant - MW (60 minutes)407
Plant Hours Connected to Load 8755 7750
Net Continuous Plant Capability (Megawatts)
When Not Limited by Condenser Water 403
When Limited by Condenser Water
Average Number of Employees
Net Generation, Exclusive of Plant Use - KWh 628158000 2852543000
Cost of Plant: Land and Land Rights 280255 9626532
Structures and Improvements 5483157 60603393
Equipment Costs 60058290 221344932
Asset Retirement Costs 1571858
Total Cost 65821702 293146715
Cost per KW of Installed Capacity (line 17/5) Including 810.1133 661.7307
Production Expenses: Oper, Supv, & Engr 142739 126116
Fuel 7200657 26482093
Coolants and Water (Nuclear Plants Only)
Steam Expenses 588663 3473239
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses 173912 147392
Misc Steam (or Nuclear) Power Expenses 914729 1566991
Rents 24340
Allowances
Maintenance Supervision and Engineering 234438
Maintenance of Structures 114659 1753206
Maintenance of Boiler (or reactor) Plant 811378 4666081
Maintenance of Electric Plant 76132 1021553
Maintenance of Misc Steam (or Nuclear) Plant 201198 122452
Total Production Expenses 10458505 39383463
Expenses per Net KWh 0166 0138
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Oil Composite Coal Oil Composite
Unit (Coal- tons/Oil-barreI/Gas-mcf/N uclear - indicate)Tons Barrels Tons Barrels
Quantity (Units) of Fuel Bumed 316150 238 1345806 5954
Avg Heat Cont - Fuel Burned (btulindicate if nuclear)10617 132599 11404 140000
Avg Cost of Fuel/unit, as Delvd t.b. during year 21.221 72.502 000 19.294 48.175 000
Average Cost of Fuel per Unit Burned 22.721 72.502 000 19.460 48.175 000
Average Cost of Fuel Burned per Million BTU 070 13.021 072 853 373 862
Average Cost of Fuel Burned per KWh Net Gen 011 000 011 009 000 009
Average BTU per KWh Net Generation 10687.020 111 10689.131 10760.621 12.273 10772.894
FERC FORM NO.1 (REV. 12-03)Page 402.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2004/04(2)D A Resubmission 04/25/2005 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses " and Maintenance Account Nos. 553 and 554 on Line 32
, "
Maintenance of Electric Plant" Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plantPlant Plant Plant Line
Name:Hunter Unit No.Name:No.
(e)
Steam Steam Steam
Outdoor Boiler Outdoor Boiler Outdoor Boiler
1980 1983 1978
1980 1983 1983
285.495.1223.
268 468 1256
8299 8469 8784
259 460 1122
220
2010041000 3575290000 8437874000
9626532 0233162 29486226
49803203 88931493 199338088
142213710 375949702 739508344
1571858 1571858 4715575
203215303 476686215 973048233
713.0362 961.8366 795.2339
126116 126116 378348
18564845 32098512 77145452
3112262 3782881 10368382
147392 147392 442176
2194293 1998056 1370754
13683 17561 55584
1809906 1718934 5282046
3177022 5410664 13253766
629626 945171 2596350
102754 139028 364234
25489313 46384315 111257092
0127 0130 0132
Coal Oil Coal Oil Composite Coal Oil Composite
Tons Barrels Tons Barrels Tons Barrels
952672 2175 1651452 10010 3949930 18139
11289 140000 11282 140000 11322 140000
19.294 48.175 000 19.294 48.175 000 19.294 48.175 000
19.372 48.175 000 19.151 48.175 000 19.310 48.175 000
858 546 863 849 009 860 853 193 862
009 000 009 009 000 009 009 000 009
10700.987 363 10707.350 10422.475 16.463 10438.938 10600.054 12.641 10612.694
FERC FORM NO.1 (REV. 12-03)Page 403.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2004/04(2)D A Resubmission 04/25/2005 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10 000 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operated
as a joint facility.4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant
;::
No.Name: Huntington
(a)(b)
Kind of Plant (Internal Comb, Gas Turb, Nuclear Steam Steam
Type of Constr (Conventional , Outdoor, Boiler, etc)Outdoor Boiler Semi-Outdoor
Year Originally Constructed 1974 1974
Year Last Unit was Installed 1977 1979
Total Installed Cap (Max Gen Name Plate Ratings-MW)996.1541.
Net Peak Demand on Plant. MW (60 minutes)907 1391
Plant Hours Connected to Load 8629 8784
Net Continuous Plant Capability (Megawatts)
When Not Limited by Condenser Water 895 1413
When Limited by Condenser Water
Average Number of Employees 164 348
Net Generation, Exclusive of Plant Use - KWh 6388634000 9820371 000
Cost of Plant: Land and Land Rights 2405337 1161925
Structures and Improvements 99455311 133679404
Equipment Costs 339245256 711525469
Asset Retirement Costs 652406 9787188
Total Cost 441758310 856153986
Cost per KW of Installed Capacity (line 17/5) Including 443.5324 555.5473
Production Expenses: Oper, Supv, & Engr 29644 12667637
Fuel 63752592 120577466
Coolants and Water (Nuclear Plants Only)
Steam Expenses 8464770 536259
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses
Misc Steam (or Nuclear) Power Expenses 6527143 9323909
Rents 890671 452888
Allowances
Maintenance Supervision and Engineering 781611 1323097
Maintenance of Structures 1231569 6104073
Maintenance of Boiler (or reactor) Plant 7970197 24371327
Maintenance of Electric Plant 2539773 9045648
Maintenance of Misc Steam (or Nuclear) Plant 1095126 1717677
Total Production Expenses 93283096 167472163
Expenses per Net KWh 0146 0171
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Coal Oil Composite Coal Oil Composite
Unit (Coal-tons/Oil-barreI/Gas-mcf/N uclear-indicate)Tons Barrels Tons Barrels
Quantity (Units) of Fuel Burned 2888019 18285 5522362 34064
Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)11179 140000 9352 140000
Avg Cost of Fuel/unit, as Delvd f.b. during year 21.889 52.126 000 21.778 51.108 000
Average Cost of Fuel per Unit Burned 21.745 52.126 000 21.519 51 . 1 08 000
Average Cost of Fuel Burned per Million BTU 973 865 986 151 692 165
Average Cost of Fuel Burned per KWh Net Gen 010 000 010 012 000 012
Average BTU per KWh Net Generation 10107.496 16.830 10124.325 10517.954 20.396 10538.350
FERC FORM NO.1 (REV. 12-03)Page 402.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2004/04(2)D A Resubmission 04/25/2005 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant" Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant
Plant Plant Plant Line
Name: Naughton Name:Name:Gadsby Steam Plant No.
(d)(1)
Steam Steam Steam
Outdoor Boiler Conventional Outdoor
1963 1978 1951
1971 1978 1955
707.289.251.64
705 278 216
8784 8140 961
700 268 235
143
5245831000 2153135000 66586000
1243566 210526 1259170
57155058 48377029 13811541
289661534 250111165 55921836
3578619
351638777 298698720 70992547
497.2268 1031.4182 282.1195
237513 3001485 27872
60497565 13659494 1676796
7449228
12975
4389599 719752 4160091
584478 7096 5928
2333073 5902
908142 420801 107246
6910552 4658589 903378
927977 1290171 1621966
766138 607475 254339
85017240 24370765 8757616
0162 0113 1315
Coal Gas Composite Coal Oil Composite Gas
Tons MCF Tons Barrels MCF
2809373 137410 1615197 7001 935228
9898 1060 8019 140000 1050
21.498 000 000 283 48.046 000 000 000 000
21.425 241 000 249 48.046 000 793 000 000
088 114 085 514 171 527 708 000 000
011 000 011 006 000 006 025 000 000
10601.301 27.771 10629.073 12031.073 19.119 12050.191 14747.019 000 000
FERC FORM NO.1 (REV. 12-03)Page 403.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2004/04(2)0 A Resubmission 04/25/2005 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10 000 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operated
as a joint facility.4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Met.7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant
No.Name: Little Mountain Name:
(a)(b)
Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbine Combined Cycle
Type of Constr (Conventional, Outdoor, Boiler, etc)Outdoor Boiler Outdoor
Year Originally Constructed 1972 1996
Year Last Unit was Installed 1972 1996
Total Installed Cap (Max Gen Name Plate Ratings-MW)16.237.
Net Peak Demand on Plant - MW (60 minutes)245
Plant Hours Connected to Load 6621 8543
Net Continuous Plant Capability (Megawatts)
When Not Limited by Condenser Water 245
When Limited by Condenser Water
Average Number of Employees
Net Generation, Exclusive of Plant Use - KWh 91965000 1867144000
Cost of Plant: Land and Land Rights 635 842245
Structures and Improvements 209660 12474622
Equipment Costs 4688107 146090385
Asset Retirement Costs 492532
Total Cost 4898402 159899784
Cost per KW of Installed Capacity (line 17/5) Including 306.1501 674.6826
Production Expenses: Oper, Supv, & Engr
Fuel 6439344 47832544
Coolants and Water (Nuclear Plants Only)
Steam Expenses
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses 732752 6522810
Misc Steam (or Nuclear) Power Expenses
Rents 184
Allowances
Maintenance Supervision and Engineering
Maintenance of Structures
Maintenance of Boiler (or reactor) Plant
Maintenance of Electric Plant
Maintenance of Mise Steam (or Nuclear) Plant 358
Total Production Expenses 7172638 54355354
Expenses per Net KWh 0780 0291
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas Gas
Unit (Coal-tons/Oil-barreI/Gas-mcf/N uclear-indicate)MCF MCF
Quantity (Units) of Fuel Burned 1457433 13237737
Avg Heat Cont - Fuel Burned (btulindicate if nuclear)1063 1021
Avg Cost of Fuel/unit, as Delvd f.b. during year 000 000 000 000 000 000
Average Cost of Fuel per Unit Burned 4.418 000 000 613 000 000
Average Cost of Fuel Burned per Million BTU 155 000 000 538 000 000
Average Cost of Fuel Burned per KWh Net Gen 070 000 000 026 000 000
Average BTU per KWh Net Generation 16852.694 000 000 7241 .352 000 000
FERC FORM NO.1 (REV. 12-03)Page 402.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2004/04(2)D A Resubmission 04/25/2005 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses.10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32
, "
Maintenance of Electric Plant" Indicate plants
designed for peak load service. Designate automatically operated plants.11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, intemal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant
Plant Plant Plant I Line
Name: Blundell Name:Name: :~!~.No.
(d)
Steam - Geothermal Steam Gas Turbine
Indoor Outdoor Boiler Outdoor
1984 1996 2002
1984 1996 2002
26.52.217.
206
8538 8728 3529
215
194876000 203419000 395480000
31282815
6218337 5733734 48460
33692461 28682437 81813
557911
71751524 34416171 130273
2749.1005 659.1873 6003
630
10916009
6661
4158192
1897624
1525679
145 17064416
77962 677
275223
91018 47415
22424 9709
6157934 29935850
0316 0000 0757
Gas
MCF
3762657
1049
000 000 000 000 000 000 000 000 000
000 000 000 000 000 000 901 000 000
000 000 000 000 000 000 766 000 000
000 000 000 000 000 000 028 000 000
000 000 000 000 000 000 9980.876 000 000
FERC FORM NO.1 (REV. 12-03)Page 403.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2004/04(2) D A Resubmission 04/25/2005 End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only.2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and intemal combustion plants of 10 000 Kw or more, and nuclear plants.3. Indicate by a footnote any plant leased or operated
as a joint facility.4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant.6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel bumed (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line Item Plant Plant
No.Name: Gadsby Gas Peakers Name:
(a)(b)(c)
Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbine
Type of Constr (Conventional, Outdoor, Boiler, etc)Outdoor
Year Originally Constructed 2002
Year Last Unit was Installed 2002
Total Installed Cap (Max Gen Name Plate Ratings-MW)141 .
Net Peak Demand on Plant. MW (60 minutes)126
Plant Hours Connected to Load 3382
Net Continuous Plant Capability (Megawatts)
When Not Limited by Condenser Water 120
When Limited by Condenser Water
Average Number of Employees
Net Generation, Exclusive of Plant Use - KWh 258948000
Cost of Plant: Land and Land Rights
Structures and Improvements 4111864
Equipment Costs 75114903
Asset Retirement Costs
Total Cost 79226767
Cost per KW of Installed Capacity (line 17/5) Including 561.8920 0000
Production Expenses: Oper, Supv, & Engr
Fuel 2660791
Coolants and Water (Nuclear Plants Only)
Steam Expenses
Steam From Other Sources
Steam Transferred (Cr)
Electric Expenses 304162
Mise Steam (or Nuclear) Power Expenses
Rents 943
Allowances
Maintenance Supervision and Engineering
Maintenance of Structures 100049
Maintenance of Boiler (or reactor) Plant
Maintenance of Electric Plant 437423
Maintenance of Misc Steam (or Nuclear) Plant 151677
Total Production Expenses 3655045
Expenses per Net KWh 0141 0000
Fuel: Kind (Coal, Gas, Oil, or Nuclear)Gas
Unit (Coal-tons/Oil-barreI/Gas-mcf/N ucl ear-ind icate)MCF
Quantity (Units) of Fuel Burned 2660164
Avg Heat Cant - Fuel Burned (btu/indicate if nuclear)1061
Avg Cost of Fuel/unit, as Delvd to.b. during year 000 000 000 000 000 000
Average Cost of Fuel per Unit Bumed 000 000 000 000 000 000
Average Cost of Fuel Burned per Million BTU 943 000 000 000 000 000
Average Cost of Fuel Burned per KWh Net Gen 010 000 000 000 000 000
Average BTU per KWh Net Generation 10902.424 000 000 000 000 000
FERC FORM NO.1 (REV. 12-Q3)Page 402.
Blank Page
(N ext Page is: 406)
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) 0 A Resubmission 04/25/2005
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10 000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group ot employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
(a)
FERC Licensed Project No. 2082
Plant Name: Copco No.
(b)
FERC Licensed Project No. 2082
Plant Name: Copco No.
(c)
Line
No.
Item
1 Kind of Plant (Run-at-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20
22 Production Expenses
23 Operatio~ Supervision and Engineering
24 Water for 'Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
Conventional
1918
1922
20.
070
um,~fRiver
Conventional
1925
1925
27.
048
931 000 516,000
180,375
216,048
560 322
627 703
105,442
689,890
434.4945
20,914
580 841
859 408
352 405
240,200
053 768
335.3247
216
285
876
440 112
569
50,147
924
43,476
37,967
643,572
0089
55,642
735
883
526,705
362
100 776
214
864
51.625
827,806
0091
FERC FORM NO.1 (REV. 12-03)Page 406
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/25/2005
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses.
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No.
Plant Name:
1927 FERC Licensed Project No.
Plant Name:
1927 FERC Licensed Project No.
Plant Name:
2420 Line
No.
Outdoor Outdoor
1953 1953 1927
1953 1953 1927
15.26.30.
739 091 035
51,849,000 750,000 36,341,000
505 129
562,166 757 988 729,490
3,411,471 035,111 020,852
962 137 151 380 668 962
219 901 566,413
935,774 11 ,164,380 490 846
329.0516 429.3992 516.3615
63,155 109,468 13,715
184 252 875
99,214 171 971 105 838
275,741 438,953 549,021
749 031 790
871 8,444 208
13,372 69,154 30,235
099 23,140 638
71,473 123,886 68,136
540 889 955 352 840 456
0104 0185 0231
FERC FORM NO.1 (REV. 12-03)Page 407
Name of Respondent
PacifiCorp
YearlPeriod of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)(2) D A Resubmission 04/25/2005
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item FERC Licensed Project No. 1927
Plant Name:
FERC Licensed Project No.
Plant Name:
Outdoor
1952
1952
11.
706
1908
1923
33.
523
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
398 000 40,277,000
560,788
936 999
387 159
400 007
284 953
753.1775
50,393
222 380
566 323
716,482
236
612 814
382.2065
313
068
73,130
226 430
282
532
19,874
126
52,413
467 190
0083
112
062
222,333
487 019
514
23,986
447 477
159 702
260,639
633 844
0654
FERC FORM NO.1 (REV. 12-03)Page 406.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
This ~rt Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) D A Resubmission 04/25/2005
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses.
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 2082
Plant Name: Iron Gate
(d)
FERC Licensed Project No. 2082
Plant Name: JC Boyle
(e)
FERC Licensed Project No.
Plant Name:
1927 Line
No.
Outdoor Outdoor
1962 1958 1955
1962 1958 1955
18.90.31.
621 617 689
96,177,000 181 ,252,000 141 161,000
341 706 984
849,624 009,060 740 316
974 336 12,715,140 575,994
077 162 10,477 032 697 485
638 679 851 851 407 171
16,881,507 26,108,067 14,420 966
937.8615 288.9659 450.7961
37,094 240,430 122,099
157 140 089
589 505 195 807
445,592 500,477 514 309
993 730 381
391 051 25,079 26,600
964 43,934 45,713
20,324 419 613 28,662
171 63,103 145,983
936,935 310,011 090,702
0097 0072 0077
FERC FORM NO.1 (REV. 12-03)Page 407.
Name of Respondent
PacifiCorp
YearlPeriod of Report
End of 2004/04
This ~ort Is: Date of Report(1) ~ An Original (Mo, Da, Yr)
(2) D A Resubmission 04/25/2005
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item FERC Licensed Project No. 1927
Plant Name:
FERC Licensed Project No.
Plant Name:
935
(a)
Outdoor
1956
1956
33.
369
Storage (Re-Reg)
Conventional
1931
1958
136.
144
781
1 Kind of Plant (Run-of-River or Storage)
2 Plant Construction type (Conventional or Outdoor)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total installed cap (Gen name plate Rating in MW)
6 Net Peak Demand on Plant-Megawatts (60 minutes)
7 Plant Hours Connect to Load
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions
11 Average Number of Employees
12 Net Generation, Exclusive of Plant Use - Kwh
13 Cost of Plant
14 Land and Land Rights
15 Structures and Improvements
16 Reservoirs, Dams, and Waterways
17 Equipment Costs
18 Roads, Railroads, and Bridges
19 Asset Retirement Costs
20 TOTAL cost (Total of 14 thru 19)
21 Cost per KW of Installed Capacity (line 20
22 Production Expenses
23 Operation Supervision and Engineering
24 Water for Power
25 Hydraulic Expenses
26 Electric Expenses
27 Misc Hydraulic Power Generation Expenses
28 Rents
29 Maintenance Supervision and Engineering
30 Maintenance of Structures
31 Maintenance of Reservoirs, Dams, and Waterways
32 Maintenance of Electric Plant
33 Maintenance of Misc Hydraulic Plant
34 Total Production Expenses (total 23 thru 33)
35 Expenses per net KWh
159,492 000
144
141
457 321,000
691 ,492
15,827 880
968,771
487,283
19,975 426
605.3159
988,467
26,608,013
686,450
441 ,508
742,299
466 737
385.7848
139,810
204
268,752
533,985
847
975
223 799
19,925
158,851
369,215
0086
934 716
587
841 177
537 267
643
254 167
748
914
430 316
097,249
0090
FERC FORM NO.1 (REV. 12-03)Page 406.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
This ~ort Is: Date of Report
(1 ) ~ An Original (Mo, Da, Yr)
(2) D A Resubmission 04/25/2005
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses.
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 1927
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
2630 Line
No.
Conventional Conventional
1950 1915 1928
1950 1920 1928
42.30.32.
783 776 584
210,970,000 18,375,000 234,970,000
698 105 168
443,619 255,340 2,482 141
392,377 537 738 18,155,764
805,191 131 975 956 213
111 ,245 394 262 191 385
10,752,432 356,013 23,890,671
252.9984 311.8671 746.5835
178,938 15,472 294 970
11 ,854 875 056
283 736 105 838 39,852
686,048 604,794 789,659
954 501 13,595
392 870 811
53,950 14,999 115,048
49,676 104 139 379
202 506 195 224
1 ,486,141 861 648 542,594
0070 0469 0066
FERC FORM NO.1 (REV. 12-03)Page 407.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2004/04(2)D A Resubmission 04/25/2005 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10 000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No. 1927 FERC Licensed Project No.
No.Plant Name: 11'!li!~~~ililii,i::;;;:i:~ii:;!i::Plant Name: 'i'il'iiiii!,il!!i:!'i'ill!MI!I:i!::,ii:llii'
(a)
Kind of Plant (Run-of-River or Storage)Run-of-River Storage
Plant Construction type (Conventional or Outdoor)Outdoor Conventional
Year Originally Constructed 1951 1924
Year Last Unit was Installed 1951 1924
Total installed cap (Gen name plate Rating in MW)18.14.
Net Peak Demand on Plant-Megawatts (60 minutes)
Plant Hours Connect to Load 457 262
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
(b) Under the Most Adverse Oper Conditions
Average Number of Employees
Net Generation, Exclusive of Plant Use - Kwh 514 000 185,000
Cost of Plant
Land and Land Rights 504 056
Structures and Improvements 783 009 577,253
Reservoirs, Dams, and Waterways 760,975 996 525
Equipment Costs 160,331 072 224
Roads, Railroads, and Bridges 16,778
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)721 093 150 058
Cost per KW of Installed Capacity (line 20 317.8385 582.1470
Production Expenses
Operation Supervision and Engineering 75,785 181
Water for Power 021 875
Hydraulic Expenses 119,057 391
Electric Expenses
Misc Hydraulic Power Generation Expenses 315 357 264 797
Rents 098 835
Maintenance Supervision and Engineering
Maintenance of Structures 473 18,229
Maintenance of Reservoirs, Dams, and Waterways 347 776
Maintenance of Electric Plant 11 ,405 230
Maintenance of Misc Hydraulic Plant 85,767 389
Total Production Expenses (total 23 thru 33)645,347 387 703
Expenses per net KWh 0074 0627
FERC FORM NO.1 (REV. 12-03)Page 406.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2004/04
This ~rt Is: Date of Report(1) ~ An Original (Mo, Da, Yr)
(2) 0 A Resubmission 04/25/2005
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses.
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No.
Plant Name:
1927 FERC Licensed Project No. 2111
Plant Name:
FERC Licensed Project No.
Plant Name:
2071 Line
No.
Storage (Re-Reg)Storage Storage
Outdoor Conventional Conventional
1952 1958 1953
1952 1958 1953
11.240.134.
222 167
104 224 523
264 165
263 165
48,874 000 568 024 000 473 703,000
813,808 777,170
830 927 044 283 022 326
224 214 633 791 160,156
772,824 15,185,856 544 337
56,124 395,145 1 ,383,555
884 089 072 883 50,887 544
716.7354 279.4703 379.7578
46,313 425 879 804 190
842 647 460
75,769 940 473 448,786
268,606 282,629 787,825
692 342 460
517 128,343 66,759
27,527 19,331 002
868 918 281
60,917 444 815 249 366
622 073 288,083 454,129
0127 0075 0052
FERC FORM NO.1 (REV. 12-03)Page 407.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2004/04(2) 0 A Resubmission 04/25/2005 End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line Item FERC Licensed Project No.FERC Licensed Project No.
No.Plant Name: ~i~'fJ~;!!::I:!!!'
!!,!!,!:;!:!!~;
!:ti:Q,,!!i Plant Name:
(a)
"""""""""""""
(c)
Kind of Plant (Run-of-River or Storage)Run-of-River
Plant Construction type (Conventional or Outdoor)Conventional
Year Originally Constructed 1904
Year Last Unit was Installed 1922
Total installed cap (Gen name plate Rating in MW)10.
Net Peak Demand on Plant-Megawatts (60 minutes)
Plant Hours Connect to Load 877
Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions
(b) Under the Most Adverse Oper Conditions
Average Number of Employees
Net Generation, Exclusive of Plant Use - Kwh 090,000
Cost of Plant
Land and Land Rights 672
Structures and Improvements 263,938
Reservoirs, Dams, and Waterways 524 049
Equipment Costs 19,801
Roads, Railroads, and Bridges 547
Asset Retirement Costs
TOTAL cost (Total of 14 thru 19)814 007
Cost per KW of Installed Capacity (line 20 79.0298 0000
Production Expenses
Operation Supervision and Engineering 709
Water for Power 644
Hydraulic Expenses 36,338
Electric Expenses
Misc Hydraulic Power Generation Expenses 322 709
Rents 615
Maintenance Supervision and Engineering
Maintenance of Structures 586
Maintenance of Reservoirs, Dams, and Waterways 394
Maintenance of Electric Plant 10,252
Maintenance of Misc Hydraulic Plant 25,777
Total Production Expenses (total 23 thru 33)418,024
Expenses per net KWh 0517 0000
FERC FORM NO.1 (REV. 12-03)Page 406.
Blank Page
(Next Page is: 410)
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2004/04
(2) LJ A Resubmission 04/25/2005
GENERATING PLANT STATISTICS (Small Plants)
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating).2. Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project,
give project number in footnote.
Line
Year Installed--aa~clty ~et Peak Net Generation
Name of Plant Orig.Name Plate atin(Demand Excluding Cost of Plant
No.Const.(In MW)Plant Use
(b)(c)(6O(Bj'n.(e)(f)
1907 520
Ashton 2381 1917 572,000
Upper Beaver 814 1907 896 000 518,404
Bend 2643 1913 524 000 859,563
1990 0.48 209,000
7 Big Fork 2652 1910 30,084 000
Cline Falls 1943 795,000 301 184
1913 15.75,252,000 886,209
1917
1914 1.40 586
Eagle Point 1957 16,872,000 789 862
Eastside 2082 1924 9,425,000 889 306
Fall Creek 2082 1903 819,000 052,083
Fountain Green 10690 1922 602 000 451,802
Granite 1896 251 000 542,181
Gunlock 9281 1917 143,000 597 257
Last Chance 4580 1983 488,000 656,187
1909 103,987I--Paris 703 1910 672 000 316 900
Pioneer 2722 1897 10,209,000
Powerdale 2659 1923 25,456,000
Prospect No.2630 1912 370,000
Prospect No.2337 1932 38,326,000
Prospect No.2630 1944 078 000
Sand Cove 9281 1926 112,000 880 783
Snake Creek 1910 982 000 902 741
Stairs 597 1895 146,000
$f;;~(tiQf1 1915 000 330,382
Veyo 9281 1920 526,000 731,669
Viva Naughton 6509 1986 112,000 158 482
Wallowa' Falls 308 1921 1.10 198,000 761,267
Weber 1744 1911 604 000 )~1
West Side 2082 1908 933,000 351 583
473 825
976 443-~~gl~.
~...~.
Pumping Plant:
Lifton 1917 253,000 11 ,298 828
Wind Turbine:
1998 32.32.103 892,000 36,266,842
FERC FORM NO.1 (REV. 12-03)Page 410
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2004/04
(2) FJ A Resubmission 04/25/2005
GENERATING PLANT STATISTICS (Small Plants) (Continued)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,
Page 403.4. If net peak demand for 60 minutes is not available, give the which is available, specifying period.5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset Operation Production Expenses Fuel Costs (in cents Line
Retire. Costs) Per MW Exc l. Fuel Fuel MaIntenance Kind of Fuel (per Million Btu)No.
(g)
(h)(i)(k)(I)
152,808 468 155 Water
279 687 305,260 98,825 Water
999,367 139,293 511 Water
774 381 109,678 894 Water
139,296 418 Water
353,287 233,709 195,030 Water
301 184 31,552 612 Water
717 313 279,123 182 Water
372,689 147,180 22,063 Water
847 441 825 Water
636 962 420,352 46,940 Water
590,408 -89,092 620 744 Water
478,220 74,544 36,145 Water
823,763 795 870 Water
271 091 96,333 063 Water
796,343 71 ,333 76,114 Water
535 368 109,182 539 Water
16,324 441 825 Water
440 139 939 13,929 Water
954 868 211 948 148 Water
142 565 312,892 471 Water
148,531 146,188 39,231 Water
946,320 292 608 90,768 Water
187 121 45,632 45,114 Water
100,979 556 884 Water
765 035 78,913 13,008 Water
179,486 604 590 Water
660 764 752 380 Water
1 ,463,338 323 963 Water
565,516 958 Water
510,243 18,866 13,861 Water
708,068 168 796 834 Water
585 972 20,410 13,994 Water
374 817
32,466 70,625
267 279 183 704 Water
111,798 895,320 Wind
FERC FORM NO.1 (REV. 12-03)Page 411
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
TRANSMISSION LINE STATIST
1. Report information concerning transmission lines, cost of lir:tes, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121 , Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
IIUN vnl T 4r..F .(K\~)LENG~H role rriles)Line (Indicate where Type of ~I(I te ! D NumberNo.other than u dergroun lines
60 cycle, 3 phase)Supporting report circuit miles)
From Operating Designed un ~trycIUre ~truc:wres CircuitsStructureof Lrn 0 ~ot Desi
8)a ed(a)(b)(c)(d)(e)
(g)
(h)
1 Malin, Oregon Indian Springs., CA 500.500.Steel Tower 47.
2 Midpoint, Idaho Malin, Oregon 500.500.Steel Tower 446.
3 Malin, Oregon Medford, Oregon 500.500.Steel Tower 84.
~ixonVilie Sub, Oregon 500.500.Steel Tower 58.
5 Malin, Oregon Captain Jack, OR 500.500.Steel Tower6~ Meridian, OR 500.500.Steel Tower 74.
Subtotal 500 kV 716.
Ben Lomond Sub., Utah Borah Substation, Idaho 345.345.Steel- H 135.
Ben Lamond Sub., Utah Terminal Substation, UT 345.345.Steel- D 47.
Spanish Fork Sub., Utah Camp Williams Sub., Utah 345.345.Steel - SP 35.
Huntington Plant, Utah Sigurd Substation, Utah 345.345.Steel- H 95.
Huntington PIt. Sub., UT Spanish Fork Sub., Utah 345.345.Steel - H 78.
Terminal Substation, UT Ninety South Sub., Utah 345.345.Steel- SP 16.
Emery Substation, Utah Sigurd Substation, Utah 345.345.Steel- H 75.
Sigurd Substation, Utah Camp Williams Sub., Utah 345.345.Steel - H-116.
Camp Williams Sub., Utah Ninety South Sub., Utah 345.345.Steel- SP
Terminal Substation, UT Camp Williams Sub., Utah 345.345.Steel- D 25.
Emery Substation, Utah Camp Williams Sub., Utah 345.345.Steel- H 121.
Newcastle, Utah Utah - Nevada Border 345.345.Steel- D 54.
Sigurd Substation, Utah Newcastle, Utah 345.345.Steel- D 137.
Goshen Substation, Idaho Kinport Substation, ID 345.345.Steel- H 41.
Huntington Plant, Utah Four Corners Sub., NM 345.345.Wood - U 101.00
Camp Williams Sub., Utah Huntington Plant, Utah 345.345.Wood - U 107.
Huntington Plant, Utah Pinto Substation, Utah 345.345.Wood. U 158.
Camp Williams Sub., Utah Sigurd Substation, Utah 345.345.Wood. U 70.
Jim Bridger Plant #3, WY Borah Substation, Idaho 345.345.Steel Tower 240.
Jim Bridger Plant #2, WY Kinport Substation, ID 345.345.SteelTower 234.
Subtotal 345 kV 894.
Fairview, Oregon Isthmus, Oregon 230.230.H Frame Wood 12.
Antelope Sub., Idaho Lost River 230kV Line, ID 230.230.Wood - H 20.
Walla Walla, Washington Hells Canyon, ID 230.230.H Frame Wood 78.
TOTAL 15,535.100.189
FERC FORM NO.1 (ED. 12-87)Page 422
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
RANSMISSION LINE STATISTICS (C ontinued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns 0) to (I) on the book cost at end of year.
COST OFTII'JE (InClUde In Column U) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(i)(k)(I)(m)(n)
(p)
1852 134,356 4,452,327 586,683
1272.086,400 151 355,378 154 441 778
1272.907 175 38,008,844 40,916,019
1272.468,204 19,737,322 21,205 526
1272.230 1,460,186 1,469 416
1272.769,43~26,247 891 017 326
374 80C 241 261,948 253,636,748
1954.229,65~35,112 853 342 506
1272.867 09~879,816 746,908
1272.978 10,158 595 16,137 212
954.343,17~20,080 786 20,423,960
954.791 811 670 321 18,462 132
1272.563 03E 7,457 557 10,020,595
954.296,57E 13,619,157 915,735
954.510,49C 19,757 078 267 568
1272.483,11 895 713 378 830
1272.313,88S 970,336 284 221
954.926 251 27,916,136 28,842 387
954.320,87~50,650,316 52,971 188
954.56,05C 13,573,405 13,629,455
t?95.313,471 571,824 885,301
1954.117 66,893,904 011,566
~95.893,961 19,131,146 20,025,111
~95.
~95.36,69~515,969 11,552,662
1272.129 03~26,209 708 338,740
1272.099,79€27,997 165 29,096,961
271 ,25~340 061 785 377 333 038
954.285,322 565,837 851 159
'95.92~200 282 213,211
1272.394 907 830 972,224
80,025,700 452 761 331 532 787 031
FERC FORM NO.1 (ED. 12-87)Page 423
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004104(2) 0 A Resubmission 04/25/2005
TRANSMISSION LINE STATIST
1. Report information concerning transmission lines, cost of lir:'es, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121 , Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (1) and (g) the total pole miles of each transmission line. Show in column (1) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
IIUN \/nl T Ar..~ J'5~)~G~H role wiles)Line Type of(Indicate wHere ot e ascrc NumberNo.other than u dergroun lines
60 cvcle. 3 chase)Supporting report circuit miles)
From Operating Designed un ~tructure ~tru1~~res CircuitsStructureof Lin 1.,:"ot er(a)(b)(c)(e)Desi
6ra ed
Ine(d)
(g)
(h)
1 Bethel, Oregon Fry, Oregon 23O.230.H Frame Wood 26.
2 Fry, Oregon Dixonville, Oregon 23O.230.H Frame Wood 45.
3 Alvey,Oregon Dixonville, Oregon 230.230.H Frame Wood 59.
4 Troutdale, Oregon Linneman, Oregon 230.230.Steel Tower
5 Troutdale, Oregon Gresham, Oregon 230.230.Steel Tower
6 McNary, Washington Walla Walla, Washington 230.230.H Frame Wood 56.
7 BPA Heppner, Oregon Dalred Substation, Orego 230.230.H Frame Wood
8 Sigurd Substation, Utah Garfield, Utah 230.230.Wood. U 117.
9 Dixonville, Oregon Reston, Oregon 230.230.H Frame Wood 17.
Yamsey, Oregon Klamath Falls, Oregon 230.230.H Frame Wood 56.
Yamsey, Oregon Klamath Falls, Oregon 230.230.Steel Tower
Dixonville, Oregon Lone Pine, Oregon 230.230.H Frame Wood
Klamath Falls, Oregon Medford, Oregon 230.230.H Frame Wood 76.
Klamath Falls, Oregon Malin, Oregon 230.230.H Frame Wood 35.
Table Rock, SW Station, OR Grants Pass, Oregon 230.230.H Frame Wood 35.
Grants Pass, Oregon Days Creek, Oregon 23O.230.H Frame Wood 71.
Dixonville, Oregon Dixonville, Oregon 230.230.Wood
Sigurd Substation, Utah Pavant Substation, Utah 230.230.Wood. U 43.
Pavant Substation, Utah Nevada - Utah State line 230.230.Wood . U 98.
Bannock Pass, Idaho Antelope Sub., Idaho 230.230.Wood. U 76.
Brady Substation, Idaho Treasureton Sub., Idaho 23O.230.Wood. U 66.
Ben Lamond Sub., Utah Naughton PIt. #1 , WY 230.230.Wood. U 88.
Sigurd Substation, Utah Arizona - Utah State line 230.230.Wood. U 149.
Birch Creek Sub., WY Railroad Substation, WY 230.230.Wood. HSW 12.
Birch Creek Sub., WY Railroad Substation, WY 230.230.Wood - HSW
Ben Lomond Sub., Utah Naughton PIt. #2, WY 23O.230.Wood. U 59.
Ben Lamond Sub., Utah Naughton PIt. #2, WY 230.230.Wood - U 29.
Chappel Creek, WY Naughton Plant, WY 230.230.Wood Tower 46.
Ben Lomond Sub., Utah Terminal Substation, UT 230.230.Steel. D-P 74.
Naughton Plant, Wyoming Treasureton Sub., Idaho 230.230.Wood. U 79.
Naughton Plant, Wyoming Treasureton Sub., Idaho 230.230.Wood. U
Swift Plant #1, WA Cowlitz Co. Line, WA 230.230.H Frame Wood
Swift Plant #2, WA BPA Woodland, WA 230.230.H Frame Wood 23.
Union Gap, Washington BPA Midway, WA 230.230.H Frame Wood 39.
Walla Walla, Washington Lewiston, ID 230.230.H Frame Wood 45.
TOTAL 535.100.189
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
RANSMISSION LINE STATISTICS (Continued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased 'from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns 0) to (I) on the book cost at end of year.
COST OF LINE (Include In Column U) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses (0)Expenses No.(i)(k)(I)(m)(n)
(p)
1272.351,98~298,770 650,752
1272.485,89€310,960 796,856
954.428,506,632 15,934,879
954.423,037 423,037
954 .363 574,074 937 791
1272.220 96/ . 3,041 516 262 483
795.108,27~108,274
795.39087E 651 768 042 646
971 558,410 598,381
i795.
r?95.247 09~113 815 360,908
~95.439,56~319,036 758,599
~95.173,6OE 786,225 959 833
1272.115,44E 1 ,597 600 713,048
~54.191 12~194 926 386 050
1272.379,961 725,824 105 785
1272.492 100 492 100
95.41 ,49~372 021 4,413,520
95.
1272.439,598 444,701
795.72,11E 002,140 074,258
795.426,12€518,653 944,779
954.22,60~503,147 525,751
954.165,05~277,573 442,627
954.181,04/520,220 701,267
1272.736,031 202,936 938,967
1272.715,127 715,127
~54.170,961 900,151 071 118
1272.572 45~818,190 390 649
954.49E 967,418 023 916
954.56~749 28,318
954.1 ,29~296,405 297 698
954.103,53~096,689 200,221
1272.172,451 652 319 824 770
1272.366 291 108,495 474 786
80,025,700 452 761 331 532 787,031
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
TRANSMISSION LINE STATIST CS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121 , Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (1) and (g) the total pole miles of each transmission line. Show in column (1) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
IIUN \In. T.dr..j;;(K~
~~~~
ra~e 6riles)Line (Indicate wHere Type of NumberNo.other than u dergroun~lrnes
60 cycle, 3 phase)Supporting report circuit miles)
From Operating Designed un ~tructure ~truCJures CircuitsStructureof Line 'lr)Other(a)(b)(c)(e)DeSi&nated Ine
(d)
(g)
(h)
1 Walla Walla, Washington Wanapum, Washington 230.230.H Frame Wood 33.
2 Pomona, Washington Wanapum, Washington 230.230.H Frame Wood 37.
3 Centralia, Washington BPA Tap, Washington 230.230.H Frame Wood
4 Pomona, Washington Wanapum, Washington 23O.230.H Frame Wood
5 Meridian Sub, OR Lone Pine Sub, OR 230.230.
6 Billings, Montana Yellowtail, Montana 230.230.H Frame Wood 59.
7 Yellowtail, Montana Muddy Ridge, Wyoming 23O.230.H Frame Wood 176.
8 Sheridan, Wyoming Decker, Montana 23O.230.H Frame Wood 13.
9 Dave Johnston Plant, WY Casper, Wyoming 230.230.H Frame Wood 31.
Yellowtail, Montana Casper, Wyoming 23O.230.H Frame Wood 147.
Rock Springs, Wyoming Kemmerer, Wyoming 230.230.H Frame Wood 71.
Rock Springs, Wyoming Atlantic City, Wyoming 230.230.H Frame Wood 69.
Thermopolis, Wyoming Riverton, Wyoming 230.230.H Frame Wood 51.00
Casper, Wyoming Riverton, Wyoming 230.230.H Frame Wood 110.
Dave Johnston Plant, WY Rock Springs, Wyoming 230.230.H Frame Wood 206.
Dave Johnston Plant, WY Spence, Wyoming 230.230.H Frame Wood 31.
Riverton, Wyoming Atlantic City, Wyoming 23O.230.H Frame Wood 50.
Rock Springs, Wyoming Flaming Gorge, Utah 23O.230.H Frame Wood 48.
Palisades, Wyoming Green River, Wyoming 230.230.H Frame Wood
Buffalo, Wyoming Gillette, Wyoming 230.230.H Frame Wood 69.
Jim Bridger Plant, WY Point of Rocks, Wyoming 230.230.H Frame Wood
Jim Bridger Plant, WY Point of Rocks, Wyoming 230.230.H Frame Wood
Dave Johnston Plant, WY Yellowcake, Wyoming 23O.230.H Frame Wood 69.
Wyodak, WY Sub. Tie Line, WY 230.230.H Frame Wood 1.00
Jim Bridger Plant, WY Point of Rocks Ln 2, WY 230.230.H Frame Wood 35.
Blue Rim, Wyoming South Trona, Wyoming 230.230.H Frame Wood 13.
Monument, Wyoming Exxon Plant, Wyoming 23O.230.H Frame Wood 13.
Firehole, Wyoming Mansface, Wyoming 230.230.Steel Pole
Firehole, Wyoming Mansface, Wyoming 230.230.H Frame Wood 10.
Monuments, Wyoming South Trona, Wyoming 230.230.H Frame Wood 24.
Spence Sub., WY Jim Bridger Plant, WY 230.H Frame Wood 47.
Jim Bridger Plant, WY Mustang Sub., Wyoming 23O.230.H Frame Wood 73.
Spence Sub., Wyoming Mustang Sub., Wyoming 230.230.H Frame Wood 77.
Rock Springs, Wyoming Flaming Gorge, Utah 230.230.Steel Tower
Line 59, CA Copco II, CA 230.230.H Frame Wood
TOTAL 15,535.100.189
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
RANSMISSION LINE STATISTICS (C ontinued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns 0) to (I) on the book cost at end of year.
COST OF LINE (lncluae In Column 0) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses (0)Expenses No.(i)(k)(I)(m)(n)
(p)
954.235,53~942,914 178,446
1780.207 12~650,601 857,724
954.33,88E 165,771 199,656
556.169 1,489,287 489,456
003,740 003,740
1272.32,99E 479,867 512 865
1272.120,94~438,473 559,422
1272.09~630 118 656,211
1795.92E 067064 081 992
1271.130 159 034 289,231
1271.90E 591 104 644 010
~54.31 ,85~404 832 436 691
1272.11~903 860 960 972
~54.851 282 517 350,374
1272.10~212,947 271 049
1272 33,OOE 658,898 691 906
1271.0 48,281 908 764 957 045
1272.30,76S 973,537 004,306
1272.635,263 635,275
1272.361,351 195,868 557 219
1272.80C 134,061 138,861
1272.130,166 130,166
1272.294 29(189,197 6,483,487
1272.15,463 15,463
1272.6,455,716 6,459,683
1272.872,422 872,422
1272.160,129 160,129
1272.
1272,674 008 674 008
1272.268,245 268,245
1272.170,295 170,295
1272.760 523 760,523
1272.542 996 542,996
1272,48~396 815 401 297
33S 820 071 824 410
80,025,700 452 761 331 532,787,031
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
TRANSMISSION LINE STATIST CS
1. Report information concerning transmission lines, cost of li':1es, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121 , Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
\/nl T M"I:: ,(KV)LENG~H role miles)Line
.. , . ,.....,
No.(Indicate wHere Type of
WI te e? of Numberother than u dergroun lines
60 cycle 3 chase)Supporting report circuit miles)
From Operating Designed un ~tructure &tru1~~res CircuitsStructureof Line Al')ot erDesi
fWated
line(a)(b)(c)(d)(e)
(g)
(h)
1 Arizona/Utah State Line Glen Canyon Sub., Arizona 230.230.H Frame Wood 10.
Miners Sub, Wyoming Foote creek Sub., Wyoming 230.230.29.
Subtotal 230 kV 311.
6 Montana-Idaho State line Grace Plant, Idaho 161.161.Wood - H 57.90.
Goshen Substation , Idaho Rigby Substation, Idaho 161.161.00 Wood - H 61.00
8 Goshen Substation, Idaho Antelope Substation, ID 161.161.00 Wood - H 45.
9 Goshen Substation, Idaho Sugar Mill Substation, ID 161.0C 161.Wood - SP 17.
Sugar Mill Sub., Idaho Rigby Substation, Idaho 161.0C 161.Wood - SP 17.
Goshen Substation, Idaho Bonneville Sub., Idaho 161.161.Wood - SP-20.
Billings, Montana Yellowtail, Montana 161.0C 161.00 H Frame Wood 46.
Big Grassy Sub., ID Idaho Power Line, ID 161.161.Wood - H 1.00
Rigby Sub., Idaho Jefferson Roberts, Idaho 161.0C 161.00 Wood. SP 18.
Thennopolis, Wyoming Wapa Tie Line #2, Wyoming 161.0C 161.00 1.00
Subtotal 161 kV 283.90.
Naughton Plant, Wyoming Evanston Substation, WY 138.138.Wood. H 67.
Evanston Substation, WY Anschutz Substation, WY 138.138.Wood. H
Evanston Substation, WY Anschutz Substation, WY 138.138.Wood. H 15.
Naughton Plant, Wyoming Carter Creek Sub., WY 138.138.Wood - H 36.
Railroad Sub., Wyoming Carter Creek Sub., WY 138.138.Wood. H 17.
Painter Substation, WY Natural Gas Sub., WY 138.138.Wood - H
Grace Plant, Idaho Terminal Sub.UT(103-104 138.138.Steel- S 42.
Grace Point, ID Terminal Sub, UT (103-138.138.Wood - H 212.
Grace Plant, Idaho Terminal Sub., UT (105)138.138.Wood - H 144.
Grace Plant, Idaho Soda Plant, Idaho 138.138.Wood. H
Oneida Plant, Idaho Ovid Substation, Idaho 138.138.Wood. H 23.
Antelope Substation, ID Scoville Sub., Idaho 138.138.Wood. H
Soda Plant, Idaho Monsanto Sub., Idaho 138.138.Wood - H
Caribou Substation, ID Grace Plant, Idaho 138.138.Wood. H 16.
Caribou Substation, ID Becker Substation, Idaho 138.138.Wood - H
Treasureton Sub., ID Franklin Sub., Idaho 138.138.Wood - H & S 10.
Franklin Substation, ID Smithfield Sub., Utah 138.138.Wood - H 25.
TOTAL 535.100.189
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
RANSMISSION LINE STATISTICS (C ontinued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sale owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns G) to (I) on the book cost at end of year.
COSTOF1Jl"JF(lnClude In Column U) Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(i)(k)(I)(m)(n)
(p)
430 671 430,671
968,612 968,612
139,751 241 579,596 251 719,341
397.18,97E 268 267 287,245
~97.52C 689,591 717 111
97.85/2,407 191 416,048
97.48,221 118,668 166,895
97.53E 926,456 953,992
354.362,27~811 683 173.962
~56.23,36E 386,146 1,409,514
~56.26,208 26,208
~56.76,30E 242,793 319,099
12,306 12,306
593,071 889,309 12,482,380
795.146 645 882,305 028,950
795.129,13C 473,050 602,180
795.381 290,803 294 184
795.411 577,595 619 006
~95.62~822,615 895,237
~95.12,42~278,836 291,260
t795.765,18E 621 364 386 549
t795.
~50.132 96C 13,907 535 040 495
~95.29C 157 293 160 583
336.0 450 080 454 897
397.14E 390 538
397.555 109,052 111 607
795.18,284 421,186 439,470
397.14,424 145,941 160,365
795.39,101 518,899 558,000
397.613 052 130 099,743
80,025 700 452 761 331 532 787,031
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
TRANSMISSION LINE STATIST
1. Report information conceming transmission lines, cost of lit:1es, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission fines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
~~~J:t~~~~~LENG~H &pole wiles)Line IIUN Type of ~'O t e a~ 0 NumberNo.other than u dergroun lines
60 cycle 3 phase)Supporting report circuit miles)
un ::?tructure ~tru1fWes CircuitsFromOperatingDesignedStructureof Line 0 ~ot Desi
fWated(a)(b)(c)(d)(e)
(g)
(h)
1 Midvalley Substation, UT Thirty South Sub., UT 138.138.Wood. H 1.00
Angel Substation, UT Smith's UT 138.138.Wood. H 1.00
Terminal Substation, UT Kennecott Sub., Utah 138.138.Steel- S
Terminal Substation, UT 30 South Switch Rack, UT 138.138.Steel- S
5 Jordan, UT Terminal Substation, UT 138.138.Wood. H
6 Wheelan Substation, Utah American Falls Sub., UT 138.138.Wood. H 82.
7 Cutler Plant, UT Wheelon Substation, UT 138.138.Wood. H 1.00
8 Terminal Substation, UT Helper Substation, Utah 138.138.Wood. H 121.
9 Hale Plant, Utah Nebo Substation, Utah 138.138.Wood. H 54.
Carbon Plant, Utah Helper Substation, Utah 138.138.Wood - H
Terminal Substation, UT Tooele Substation, Utah 138.138.Wood. H 29.
Wheelon Substation, Utah Smithfield Sub., Utah 138.138.Wood. H 20.1.00
Helper Substation, Utah Moab Substation, Utah 138.138.Wood - H 118.
Ninetieth South Sub, Utah Carbon Plant, Utah 138.138.Wood - H 75.
Terminal Substation, UT Ninetieth South Sub, UT 138.138.Wood - H 16.
30 South Switch Rack, UT McClelland Sub., Utah 138.138.Wood - SP
Moab Substation, Utah Pinto Substation, Utah 138.138.Wood. H 58.
Pinto Substation, Utah Abajo, UT 138.138.Wood. H 45.
Carbon PI8f)t, Utah Ashley Substation, Utah 138.138.Wood. H 92.
McClelland Sub., Utah Cottonwood Sub., Utah 138.138.Wood. SP
Ashley Substation, Utah Vernal Substation, Utah 138.138.Wood. H 12.
Sigurd Substation, Utah West Cedar Substation, UT 138.138.Wood. H 120.
Ben Lomond Sub., Utah EI Monte Substation, UT 138.138.Wood. H Sub 19.
Cottonwood Sub., Utah Ninetieth South Sub, Uta 138.138.Wood. SP 11.
Terminal Substation, UT Rowley Substation, Utah 138.138.Wood. H 56.
Huntington Plant, Utah McFadden Substation, UT 138.138.Wood. H
Ben Lomond Sub., Utah EI Monte Substation, UT 138.138.Wood - H 13.
Cottonwood Sub., Utah Silvercreek Sub., Utah 138.138.Wood. SP 37.
Ninetieth South Sub, Utah Taylorsville Sub., Utah 138.138.Wood. SP
Gadsby Plant, Utah McClelland Sub., Utah 138.138.Wood. SP
Ninetieth South Sub, Utah Oquirrh Substation, Utah 138.138.Wood. SP
Nebo, UT Jerusalem, UT 138.138.Wood Tower 26.
Ben Lomond Sub., Utah Westem Zircon Sub., UT 138.138.Wood. H 14.
Tooele Substation , Utah Oquirrh Substation, Utah 138.138.Wood. SP 21.
Wheelan Substation, Utah Nucor Steel Sub., Utah 138.138.Wood - H 14.
TOTAL 535.100.189
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
RANSMISSION LINE STATISTICS (C ontinued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (1) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns 0) to (I) on the book cost at end of year.
COST OF LINE (Include In Column m Land,EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total LineOther Costs Expenses Expenses (0)Expenses No.(i)(k)(I)(m)(n)
(p)
193,583 193 583
20,229 20,229
250.658 475,562 480,220
500.83(197 446 199,283
661 44(773 167 434,614
250.118,18C 149,881 268,061
~50.072 69,072
~50.458,79~568,421 027 220
397.54~486 529 514 074
954.78E 98,978 99,764
397.801 290,530 295,331
397.188,896,472 084,490
397.33,96~663,931 697 899
795.345,83.:123,870 469,705
1272.427,552 053,575 481 127
795.62,11 ~564,970 627,083
397.40,115 996,661 036,776
397.43,002 089,679 132 681
397.47,374 725,080 772,454
795.13,73~244 816 258,549
397.546 272,179 277,725
397.52,28C 081,473 133,753
795.18,845 729 676 748,521
795.549,064 785,356 334,420
795.222 286 2,254 369 476 655
397.264 234,826 235,090
795.901 916,563 941,464
~97.177 824 872,020 049,844
95.17E 435 845 441 023
95.56,75S 925,859 982 618
795.243,445 314,079 557 524
397.253,53S 159,364 412 903
)50.96,45 968,211 064 668
95.252,891 034,761 287 652
795.46,94/909,120 956,067
80,025 700 452 761 331 532,787 031
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
TRANSMISSION LINE STATIST CS
1. Report information concerning transmission lines, cost of Ii':les, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts.Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121 , Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
~~ch~~~;~~~~G~H role rpiles)Line IIUN Type of /) t e a Number
No.other than u dergroun lines
60 cvcle 3 phase)Supporting report circuit miles)
From
un ~tructure &truCJures CircuitsOperatingDesignedStructure. Line 0 "loother
(a)(b)(c)(e)Desl
(Wated
Ine
(d)
(g)
(h)
1 Nebo Substation, Utah Martin-Marietta Sub., UT 138.138.Wood - H 30.
West Cedar Sub., Utah Middleton Substation., UT 138.138.Wood - H 69.
Gadsby Plant, Utah Terminal Substation, UT 138.138.Wood - H
Oquirrh Substation, Utah Kennecott Sub., Utah 138.138.Wood - H
Oquirrh Substation, Utah Barney Substation, Utah 138.138.Wood - HS
West Cedar Sub., Utah Pepcon Substation, Utah 138.138.Wood. SP 13.
Taylorsville Substation , UT Mid-Valley Substation, UT 138.138.Steel- SP
Warren Substation, Utah Kimberly Clark Sub., UT 138.138.Wood. HP 14.
Honeyville, Utah Promontory, Utah 138.138.Wood Tower 24.
Ninetieth South Sub, Utah Hale Plant, Utah 138.138.Wood Tower 45.
Dumas, UT Bimple, UT 138.138.Wood Tower
Columbia Sub, Utah Sunnyside Co. Gen., Utah 138.138.Wood Tower
Syracuse Sub, Utah Ben Lomond Sub, Utah 138.138.Steel- D-18.
Hale Plant, Utah Midway Sub, Utah 138.138.Wood. H 19.
Jordan 138 kV, UT Fifth West 138 kV, UT 138.138.Steel Tower 1.00
Gadsby 138 kV, UT Jordan 138 kV, UT 138.138.Steel Tower 1.00
138 kV Riverdale Sub, UT 138 kV Riverdale Sub, U 138.138.Steel Tower 1.00
Panther, UT Willow Creek, UT 138.138.Wood Tower 1.00
Hammer Substation, UT Butlerville Substation, U 138.138.Wood Tower
Midway Substation, UT Silver Creek Sub, UT 138.138.Wood Tower
Midway Substation, UT Cottonwood Sub, UT 138.138.Wood Tower 10.
McFadden Substation, UT Blackhawk Substation, Uta 138.138.11.
Subtotal 138 kV 049.
All 115 kV lines 115.115.Wood & Steel 544.
All 69 kV lines 69.69.Wood & Steel 972.1.00
All 57 kV lines 57.57.Wood & Steel 113.
All 46 kV lines 46.46.Wood & Steel 653.
TOTAL 535.100.189
FERC FORM NO.1 (ED. 12-87)Page 422.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) D A Resubmission 04/25/2005
RANSMISSION LINE STATISTICS (C ontinued)
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (1) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns 0) to (I) on the book cost at end of year.
COST OF LINE (InClude In Column 0) Land EXPENSES, EXCEPT DEPRECIATION AND TAXES
Size of Land rights, and clearing right-of-way)
Conductor
and Material Land Construction and Total Cost Operation Maintenance Rents Total Line
Other Costs Expenses Expenses (0)Expenses No.(i)(k)(I)(m)(n)
(p)
397.66,452 762 997 829,449
397.14/J 593,425 618,573
1272.668 771 810,473 479.244
795.201,459 201 459
795.16,66S 455,106 471 774
795.43,59(088 222 131 812
1272.46E 492 894 526 360
?97.72~141 422 156 144
397.475,68~874 162 349,
~97.146,42E 216,165 362,590
397.136,585 136,585
397.
1272.353,104 353,104
~97.24650~938,520 185,023
1272.078,958 078,974
1272.75E 381 900 382,655
~95.90,674 90,674
~97.40,890 40,890
188,391 364 795 553,186
755,012 2,755 012
690,025 514 849 204 874
747,47C 747 47C
511 149 766 639 158,278 343
510,35E 109 397,560 112 907 915
257,34~187 692 332 190 949,675
41,063 275 104 509
326,18~164 048,887 168 375,076
025 700 452 761 331 532 787 031
FERC FORM NO.1 (ED. 12-87)Page 423.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
RANSMISSION LINES ADDED DURING YEAR
1. Report below the information called for concerning Transmission lines added or altered during the year.It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (I) to (0), it is permissible to report in these columns the
Line UN I:. IUN LIne Svrrvn liNG::) 'RUe.; JURI:.r :I~r :1111::) PER STRUCTURLe!1gth
No.From Type umber per Present Ultimate
Miles Miles
(a)(b)(c)(d)(e)(f)
(g)
1 Silver Creek Jordanelle Steel Dbl Ckt.15.
Silver Creek Jordanelle Steel Sngl PI 15.
3 Kearns Taylorsville Wood Sngl PI 18.
4 Manila Tap Manila Wood Sngl PI 21.
5 Rocky Point Tap Rocky Point Wood Sngl PI 18.
6 Riverdale Farmington 21.Steel Dbl Ckt.11.
TOTAL 39.98.
FERC FORM NO.1 (REV. 12-03)Page 424
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
TRAN )MISSION LINES ADDED DURING Y AR (Continued)
costs. Designate, however, if estimated amounts are r~ported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (I) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,
indicate such other characteristic.
IUH~LINE COST LineVoltage
Size Specification conf~uration Land and Poles, Towers Conductors Asset Total No.and pacing (Operating)Land Rights and Fixtures and Devices Retire. Costs
(h)(i)(k)(I)(m)(n)(0)
397.5 MCM ACSR VerticaV1 0'138
795 MCM ACSR VerticaV1 138 144 97S 488 106 633,084
795 MCM ACSR VerticaV10'138 642,21C 842,022 484 232
1272 MCM ACSR VerticaV10'138 476,643 476,643 953,286
397.5 MCM ACSR VerticaV10'138 484 27,484
795 MCM ACSR VerticaV10'138 154 039 154 039 308,078
445,35~960 810 406,164
FERC FORM NO.1 (REV. 12-03)Page 425
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
California
BIG SPRINGS DISTRIBUTION-UNA TTEN 69.12.
CANBY #2 DISTRIBUTION-UNA TTEN 69.2.40
CASTELLA DISTRIBUTION-UNA TTEN 69.2.40
CLEAR LAKE DISTRIBUTION-UNA TTEN 69.12.
CRESCENT CITY DISTRIBUTION-UNA TTEN 12.
DOG CREEK DISTRIBUTION-UNA TTEN 69.
FORT JONES DISTRIBUTION-UNA TTEN 69.12.47
GREENHORN DISTRIBUTION-UNA TTEN 69.12.
HAMBURG DISTRIBUTION-UNA TTEN 69.2.40
HAPPY CAMP DISTRIBUTION-UNA TTEN 69.12.
HORNBROOK DISTRIBUTION-UNA TTEN 69.12.47
INTERNATIONAL PAPER DISTRIBUTION-UNA TTEN 69.2.40
LAKE EARL DISTRIBUTION-UNA TTEN 69.12.
LITTLE SHASTA DISTRIBUTION-UNA TTEN 69.
LUCERNE DISTRIBUTION-UNA TTEN 69.12.
MACDOEL DISTRIBUTION-UNA TTEN 69.20.
MCCLOUD DISTRIBUTION-UNA TTEN 69.12.
MONTAGUE DISTRIBUTION-UNA TTEN 69.12.47
MOUNT SHASTA DISTRIBUTION-UNA TTEN 69.12.
NORTH DUNSMUIR DISTRIBUTION-UNA TTEN 69.12.
NUTGLADE DISTRIBUTION-UNATTEN 69.2.40
SCOTT BAR DISTRIBUTION-UNA TTEN 69.12.
SEIAD DISTRIBUTION-UNA TTEN 69.12.
SHASTINA DISTRIBUTION-UNA TTEN 69.20.
SHOTGUN CREEK DISTRIBUTION-UNA TTEN 69.12.47
SNOW BRUSH DISTRIBUTION-UNA TTEN 69.
SOUTH DUNSMUIR DISTRIBUTION-UNA TTEN 69.
TULELAKE DISTRIBUTION-UNATTEN 69.12.
TUNNEL DISTRI BUTION-UNA TTEN 69.12.
TURKEY HILL DISTRIBUTION-UNA TTEN 69.12.
WALKER BRYAN DISTRIBUTION-UNA TTEN 69.12.
WEED DISTRIBUTION-UNATTEN 69.12.47
YUBA DISTRIBUTION-UNATTEN 69.12.
YUROK DISTRIBUTION-UNATTEN 69.12.
Total 2289.353.
NUMBER OF SUBSTATIONS DIST UNATTENDED - 34
AL TURAS TID-UNATTENDED 115.12.69.
FALL CREEK HYDROI T/D-UNATTENDED 69.
FERC FORM NO.1 (ED. 12-96)Page 426
Name of Respondent This 'OOort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04
(2) LJ A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, e~c.and auxiliary equipment for
Increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
240
FERC FORM NO.1 (ED. 12-96)Page 427
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
YREKA T/D-UNA TTENDED 115.12.69.
Total 299.27.138.
NUMBER OF SUBSTATIONS TID UNATTENDED - 3
AGER TRANSMISSION-ATTEND 115.69.
COPCO #1 HYDRO PLANT TRANSMISSION-ATTEND 69.
COPCO #2 HYDRO PLANT TRANSMISSION-ATTEND 69.
COPCO #2 TRANSMISSION-ATTEND 69.12.47
COPCO #2 TRANSMISSION-ATTEND 230.115.
Total 552.205.
NUMBER OF SUBSTATIONS TRANS ATTENDED - 5
CRAG VIEW TRANSMISSION-UNA TTEN 115.69.
DEL NORTE TRANSMISSION-UNA TTEN 115.69.
IRON GATE HYDRO PLANT TRANSMISSION-UNA TTEN 69.
WEED JUNCTION TRANSMISSION-UNA TTEN 115.69.
Total 414.213.
NUMBER OF SUBSTATIONS TRANS UNATTENDED - 4
Idaho
ALEXANDER DISTRIBUTION-UNA TTEN 46.12.
AMALGA DISTRIBUTION-UNA TTEN 46.12.47
AMMON DISTRIBUTION-UNA TTEN 69.12.47
ARCO DISTRIBUTION-UNA TTEN 69.12.
ARIMO DISTRIBUTION-UNA TTEN 46.12.
BANCROFT DISTRIBUTION-UNA TTEN 46.12.
BELSON DISTRIBUTION-UNA TTEN 69.12.47
BERENICE DISTRIBUTION-UNA TTEN 69.12.
CAMAS DISTRIBUTION-UNA TTEN 69.12.47
CANYON CREEK DISTRIBUTION-UNA TTEN 69.24.
CHESTERFIELD DISTRIBUTION-UNA TTEN 46.12.
CLEAR CREEK DISTRIBUTION-UNA TTEN 46.12.47
CLEMENT DISTRIBUTION-UNA TTEN 69.12.
CLIFTON DISTRIBUTION-UNA TTEN 46.12.
DOWNEY DISTRIBUTION-UNA TTEN 46.12.
DUBOIS DISTRIBUTION-UNA TTEN 69.12.47
EASTMONT DISTRIBUTION-UNA TTEN 69.12.
EGIN DISTRIBUTION-UNA TTEN 69.12.
EIGHT MILE DISTRIBUTION-UNA TTEN 46.12.
FOOL CREEK DISTRIBUTION-UNA TTEN 46.12.47
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), G), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
129
125
220
150
226
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2004/04(2) i:i A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
GEORGETOWN DISTRIBUTION-UNA TTEN 69.12.47
GRACE CITY STATION DISTRIBUTION-UNA TTEN 46.12.47
HAMER DISTRIBUTION-UNA TTEN 69.12.
HAYES DISTRIBUTION-UNA TTEN 69.12.47
HENRY DISTRIBUTION-UNA TTEN 46.12.
HOLBROOD DISTRIBUTION-UNA TTEN 69.12.47
HOOPES DISTRIBUTION-UNA TTEN 69.12.
HORSLEY DISTRIBUTION-UNA TTEN 46.12.
IDAHO FALLS DISTRIBUTION-UNA TTEN 46.12.47
INDIAN CREEK DISTRIBUTION-UNA TTEN 69.12.
JEFFCO DISTRIBUTION-UNA TTEN 69.24.
KETTLE DISTRIBUTION-UNA TTEN 69.24.
LAVA DISTRIBUTION-UNA TTEN 46.12.
LEWISTON DISTRIBUTION-UNA TTEN 46.12.
LOGAN CANYON DISTRIBUTION-UNA TTEN 46.
LUND DISTRIBUTION-UNA TTEN 46.12.
MCCAMMON DISTRIBUTION-UNA TTEN 46.12.
MENAN DISTRIBUTION-UNA TTEN 69.12.47
MILLER DISTRIBUTION-UNA TTEN 69.12.
MILLVILLE DISTRIBUTION-UNATTEN 46.12.
MONTPELIER DISTRIBUTION-UNA TTEN 69.12.
MOODY DISTRIBUTION-UNA TTEN 69.24.
NEWDALE DISTRIBUTION-UNA TTEN 69.12.
NEWTON DISTRIBUTION-UNA TTEN 46.12.47
NIBLEY DISTRIBUTION-UNA TTEN 46.24.
NORTH LOGAN DISTRIBUTION-UNATTEN 46.12.47
OSGOOD DISTRIBUTION-UNA TTEN 69.12.47
PRESTON DISTRIBUTION-UNA TTEN 46.12.
RANDOLPH DISTRIBUTION-UNA TTEN 46.12.
RAYMOND DISTRIBUTION-UNA TTEN 69.12.
RENO DISTRIBUTION-UNA TTEN 69.12.47
REXBURG DISTRIBUTION-UNA TTEN 69.12.
RICH DISTRIBUTION-UNA TTEN 69.12.
RICHMOND DISTRIBUTION-UNA TTEN 46.12.
RIRIE DISTRIBUTION-UNA TTEN 69.12.47
ROBERTS DISTRIBUTION-UNA TTEN 69.12.
RUDY DISTRIBUTION-UNA TTEN 69.12.
SAND CREEK DISTRIBUTION-UNA TTEN 69.12.47
SAN DUNE DISTRIBUTION-UNA TTEN 69.24.
SHELLEY DISTRIBUTION-uNA TTEN 46.12.47
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
ooort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
SMITH DISTRIBUTION-UNA TTEN 69.12.
SODA DISTRIBUTION-UNA TTEN 138.
SOUTH FORK DISTRIBUTION-UNA TTEN 69.12.
SPUD DISTRIBUTION-UNA TTEN 46.12.
ST. CHARLES DISTRIBUTION-UNA TTEN 69.12.
SUGAR CITY DISTRIBUTION-UNA TTEN 69.12.
SUNNYDELL DISTRIBUTION-UNA TTEN 69.12.47
TANNER DISTRIBUTION-UNA TTEN 46.12.
TARGHEE DISTRIBUTION-UNATTEN 46.12.47
THORNTON DISTRIBUTION-UNA TTEN 69.12.
UCON DISTRIBUTION-UNA TTEN 69.12.
WATKINS DISTRIBUTION-UNA TTEN 69.12.47
WEBSTER DISTRIBUTION-UNA TTEN 69.12.
WESTON DISTRIBUTION-UNA TTEN 46.12.
WINDSPER DISTRIBUTION-UNA TTEN 69.24.
Total 4531.00 1011.
NUMBER OF SUBSTATIONS DIST UNATTENDED - 75
MALAD T ID-UNA TTENDED 138.46.12.
MUD LAKE T/D-UNA TTENDED 69.12.
RIGBY T ID-UNA TTENDED 161.12.47 69.
SAINT ANTHONY T/D-UNA TTENDED 69.46.12.
Total 437.116.93.
NUMBER OF SUBSTATIONS T/D UNATTENDED - 4
GRACE HYDRO TRANSMISSION-ATTEND 138.46.
Total 138.46.
NUMBER OF SUBSTATIONS TRANS ATTENDED -
AMPS TRANSMISSION-UNA TTEN 230.69.
ANTELOPE TRANSMISSION-UNA TTEN 230.161.
ASHTON PLANT TRANSMISSION-UNA TTEN 46.
BIG GRASSY TRANSMISSION-UNA TTEN 161.69.
BONNEVILLE TRANSMISSION-UNA TTEN 161.69.
CARIBOU TRANSMISSION-UNA TTEN 138.46.
GONDA TRANSMISSION-UNA TTEN 138.46.
COVE PLANTI TRANSMISSION-UNA TTEN 46.
FISH CREEK TRANSMISSION-UNA TTEN 161.46.
FRANKLIN TRANSMISSION-UNA TTEN 138.69.
GOSHEN TRANSMISSION-UNA TTEN 345.161.46.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
835
189
314
115
115
250
763
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
GREEN CANYON TRANSMISSION-UNA TTEN 138.46.
JEFFERSON TRANSMISSION-UNA TTEN 161.69.
LIFTON HYDRO TRANSMISSION-UNA TTEN 69.
ONEIDA TRANSMISSION-UNA TTEN 138.12.
OVID TRANSMISSION-UNA TTEN 138.69.
SMITHFIELD TRANSMISSION-UNA TTEN 136.46.12.
SUGARMILL TRANSMISSION-UNA TTEN 161.46.69.
TREASURETON TRANSMISSION-UNA TTEN 230.138.
Total 2965.1173.127.
NUMBER OF SUBSTATIONS TRANS UNATTENDED -
Oregon
BLOSS DISTRIBUTION-UNA TTEN 115.12.
CANNON BEACH DISTRIBUTION-UNA TTEN 115.12.47
COLUMBIA DISTRIBUTION-UNA TTEN 115.12.47 57.
CULLY DISTRIBUTION-UNA TTEN 115.12.47
FERN HILL DISTRIBUTION-UNA TTEN 115.12.47
26TH STREET DISTRIBUTION-UNA TTEN 20.
35TH STREET DISTRIBUTION-UNA TTEN 20.
AGNESS AVE DISTRIBUTION-UNA TTEN 115.12.
ALDERWOOD DISTRIBUTION-UNA TTEN 69.12.
ARLINGTON DISTRIBUTION-UNA TTEN 69.12.
ATHENA DISTRIBUTION-UNATTEN 69.12.
BALD MT MAGAMA-FII DISTRIBUTION-UNA TTEN 20.
BANDON TIE DISTRIBUTION-UNA TTEN 20.12.
BAUMAN FII DISTRIBUTION-UNA TTEN 20.
BEACON DISTR I BUTION-U NA TTEN 69.12.
BEATTY DISTRIBUTION-UNA TTEN 69.12.
BELKNAP DISTRIBUTION-UNA TTEN 69.12.
BELMONT DISTRIBUTION-UNA TTEN 69.12.
BLALOCK DISTRIBUTION-UNA TTEN 69.12.
BLY DISTRIBUTION-UNA TTEN 69.12.
BOISE CASCADE DISTRIBUTION-UNA TTEN 69.11.
BONANZA DISTRIBUTION-UNA TTEN 69.12.
BROOKHURST DISTRIBUTION-UNA TTEN 115.12.47
BROOKS-SCANLON DISTRIBUTION-UNATTEN 69.12.47
BROWNSVILLE DISTRIBUTION-UNA TTEN 69.20.
BRYANT DISTRIBUTION-UNA TTEN 69.12.
BUCHANAN DISTRIBUTION-UNA TTEN 115.20.
BUCKAROO DISTRIBUTION-UNA TTEN 69.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(1)
(g)
(h)(i)(k)
233
168
533
2646
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent Th'S ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04
(2)A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
CAMPBELL DISTRIBUTION-UNA TTEN 115.12.47
CARNES DISTRIBUTION-UNA TTEN 69.12.
CASEBEER DISTRIBUTION-UNA TTEN 69.20.
CAVEMAN DISTRIBUTION-UNA TTEN 115.12.
CHERRY LANE DISTRIBUTION-UNA TTEN 69.12.47
CHILOOUIN MARKET DISTRIBUTION-UNA TTEN 69.12.
CHINA HAT DISTRIBUTION-UNA TTEN 69.12.
CIRCLE BLVD DISTRIBUTION-UNA TTEN 115.20.
CLEVELAND AVE DISTRIBUTION-UNA TTEN 69.12.
CLINE FALLS HYDRO DISTRIBUTION-UNATTEN 12.2.40
CLOAKE DISTRIBUTION-UNA TTEN 69.20.
COBURG DISTRIBUTION-UNA TTEN 69.20.
COLISEUM DISTRIBUTION-UNA TTEN 20.
COOS RIVER DISTRIBUTION-UNATTEN 115.20.
CO~UiLLE DISTRIBUTION-UNA TTEN 115.20.
CROOKED RNER RANCH DISTRIBUTION-UNA TTEN 69.20.
CROWFOOT DISTRIBUTION-UNA TTEN 115.12.47
CULVER DISTRIBUTION-UNA TTEN 69.12.
CUTLER CITY DISTRIBUTION-UNA TTEN 20.
DAIRY DISTRIBUTION-UNA TTEN 69.12.
DALLAS DISTRIBUTION-UNA TTEN 115.20.
DALREED DISTRIBUTION-UNA TTEN 230.34.
DESCHUTES DISTRIBUTION-UNA TTEN 69.12.
DEVILS LAKE DISTRIBUTION-UNA TTEN 115.20.
DIXON DISTRIBUTION-UNA TTEN 115.
DODGE BRIDGE DISTRIBUTION-UNATTEN 69.20.
DORRIS DISTRIBUTION-UNA TTEN 69.12.
DOUGLAS LUMBER #1 DISTRIBUTION-UNATTEN 12.
DOUGLAS LUMBER #1 DISTRIBUTION-UNA TTEN 20.
DOUGLAS LUMBER #1 DISTRIBUTION-UNA TTEN 20.
DOUGLAS LUMBER #1 DISTRIBUTION-UNA TTEN 20.12.
EAGLE VENEER FII DISTRIBUTION-UNA TTEN 20.
EAST VALLEY DISTRIBUTION-UNA TTEN 115.12.47
EMPIRE DISTRIBUTION-UNA TTEN 115.20.
ENTEK NORTH FII DISTRI BUTION-U NA TTEN 20.0.48
ENTEK SOUTH FII DISTRIBUTION-UNATTEN 20.
ENTERPRISE DISTRIBUTION-UNA TTEN 69.12.
FIELDER CREEK DISTRIBUTION-UNA TTEN 115.20.
FOOTHILLS DISTRIBUTION-UNA TTEN 69.12.
FRALEY DISTRIBUTION-UNA TTEN 69.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.
In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
GARDEN VALLEY DISTRIBUTION-UNA TTEN 69.20.
GASOUET DISTRIBUTION-UNA TTEN 115.12.
GAZLEY DISTRIBUTION-UNA TTEN 69.12.
GEARHART DISTRIBUTION-UNA TTEN 12.
GLENDALE DISTRIBUTION-UNA TTEN 230.12.47
GLEN EDEN DISTRIBUTION-UNA TTEN 20.
GLIDE DISTRIBUTION-UNA TTEN 115.12.
GOLD HILL DISTRIBUTION-UNA TTEN 69.12.
GORDON HOLLOW DISTRIBUTION-UNA TTEN 69.12.
GOSHEN DISTRIBUTION-UNA TTEN 115.20.
GRANT STREET DISTRIBUTION-UNA TTEN 115.20.
GRASS VALLEY DISTRIBUTION-UNA TTEN 20.
GREEN DISTRIBUTION-UNA TTEN 69.12.
GRIFFIN CREEK DISTRIBUTION-UNA TTEN 115.12.47
HAMAKER DISTRIBUTION-UNA TTEN 69.12.
HARRISBURG DISTRIBUTION-UNA TTEN 69.20.
HENLEY DISTRIBUTION-UNATTEN 69.12.47
HERMISTON DISTRIBUTION-UNA TTEN 69.12.
HILL VIEW DISTRIBUTION-UNA TTEN 115.20.
HINKLE DISTRIBUTION-UNA TTEN 69.12.
HOLLADAY DISTRIBUTION-UNA TTEN 115.12.47
HOLLYWOOD DISTRIBUTION-UNA TTEN 115.12.47
HOOD RIVER DISTRIBUTION-UNA TTEN 69.12.47
HORNET DISTRIBUTION-UNA TTEN 69.12.47
INDEPENDENCE DISTRIBUTION-UNA TTEN 69.20.
JACKSONVILLE DISTRIBUTION-UNA TTEN 115.12.47 69.
JEFFERSON DISTRIBUTION-UNA TTEN 69.20.
JEROME PRAIRIE DISTRIBUTION-UNA TTEN 115.12.
JORDAN POINT DISTRIBUTION-UNA TTEN 115.12.
JOSEPH DISTRIBUTION-UNATTEN 20.12.47
JUNCTION CITY DISTRIBUTION-UNA TTEN 69.20.
KENWOOD DISTRIBUTION-UNA TTEN 69.12.
KILLINGWORTH DISTRIBUTION-UNA TTEN 69.12.
KNAPPA SVENSEN DISTRIBUTION-UNA TTEN 115.12.
LAKEPORT DISTRIBUTION-UNA TTEN 69.12.47
LAKEVIEW DISTR I BUTION-U NA TTEN 69.12.47
LANCASTER DISTRI BUTION-U NA TTEN 69.20.
LEBANON LUMBER DISTRIBUTION-UNA TTEN 20.
LEBANON DISTRIBUTION-UNA TTEN 115.20.
LINCOLN DISTRIBUTION-UNA TTEN 115.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), m, and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
115
105
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation , designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
LOCKHART DISTRIBUTION-UNA TTEN 115.20.
LYONS DISTRIBUTION-UNA TTEN 69.20.
MADRAS DISTRIBUTION-UNA TTEN 69.12.47
MALLORY DISTRIBUTION-UNA TTEN 115.12.47
MARYS RIVER DISTRIBUTION-UNA TTEN 115.20.
MEDCO DISTRIBUTION-UNA TTEN 115.12.47
MEDFORD DISTRIBUTION-UNA TTEN 69.12.
MERLIN DISTRIBUTION-UNA TTEN 115.12.
MERRILL DISTRIBUTION-UNA TTEN 69.12.
MILLER REDWOOD DISTRI BUTION-UNA TTEN 69.12.
MILTON #10 FII DISTRIBUTION-UNA TTEN 20.
MILTON #9 FII DISTRIBUTION-UNA TTEN 20.
MINAM DISTRIBUTION-UNA TTEN 69.12.47
MODOC DISTRIBUTION-UNA TTEN 69.12.
MORO DISTRIBUTION-UNA TTEN 20.2.40
MURDER CREEK DISTRIBUTION-UNA TTEN 115.20.
MURPHY DISTRIBUTION-UNA TTEN 20.12.47
MURPHY DISTRIBUTION-UNA TTEN
MYRTLE CREEK DISTRIBUTION-UNA TTEN 69.12.
MYRTLE POINT DISTRIBUTION-UNA TTEN 115.20.
NATIONAL FROZEN-FII DISTRIBUTION-UNA TTEN 20.
NELSCOTT DISTRIBUTION-UNA TTEN 20.
NEW O'BRIEN DISTRIBUTION-UNA TTEN 115.12.
NEWELL DISTRIBUTION-UNA TTEN 69.12.47
NORDIC PLYWOOD DISTRIBUTION-UNA TTEN 20.
NORTHCREST DISTRIBUTION-UNATTEN 69.12.47
OAK KNOLL DISTRIBUTION-UNA TTEN 115.12.
OAKLAND DISTRIBUTION-UNA TTEN 115.12.47
ORCHARD STREET DISTRIBUTION-UNA TTEN 12.47
OREMET FORGE -FII DISTRIBUTION-UNA TTEN 20.
OVERPASS DISTRIBUTION-UNA TTEN 69.12.47
PACIFIC CAST -FII DISTRIBUTION-UNA TTEN 20.
PACIFIC PLY D ISTRI BUTION-U NA TTEN 69.
PALLETTE DISTRI BUTION-U NA TTEN 69.20.
PARK STREET DISTRIBUTION-UNA TTEN 115.12.47
PARKROSE DISTRIBUTION-UNA TTEN 57.12.
PATRICKS CREEK DISTRIBUTION-UNA TTEN 115.
PELLET MILL DISTRIBUTION-UNA TTEN 20.
PENDLETON DISTRIBUTION-UNA TTEN 69.12.
PEREZ DISTRIBUTION-UNA TTEN 69.12.47
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
100
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
PILOT ROCK DISTRIBUTION-UNA TTEN 69.12.47
POWELL BUTTE DISTRIBUTION-UNA TTEN 115.12.
PRINEVILLE DISTRI BUTION-UNA TTEN 115.12.47
PROVOL T DISTRIBUTION-UNA TTEN 69.12.
OUEEN AVE DISTRIBUTION-UNA TTEN 69.20.
RED BLANKET DISTRIBUTION-UNA TTEN 69.
REDMOND DISTRIBUTION-UNA TTEN 115.12.47
REDWOOD DISTRIBUTION-UNA TTEN 69.12.
RICH MANUFACTURING DISTRIBUTION-UNA TTEN 57.12.
RIDDLE DISTRIBUTION-UNA TTEN 69.12.47
RIDDLE VENEER DISTRIBUTION-UNA TTEN 69.12.
ROGUE RIVER DISTRIBUTION-UNATTEN 69.12.47
ROSEBU RG DISTRIBUTION-UNA TTEN 115.20.
ROSS AVE DISTRIBUTION-UNA TTEN 69.12.47
RUCH DISTRIBUTION-UNA TTEN 69.12.47
RUNNING Y DISTRIBUTION-UNA TTEN 69.20.
RUSSELLVILLE DISTRIBUTION-UNA TTEN 115.12.
SAGE ROAD DISTRIBUTION-UNA TTEN 115.12.
SCENIC DISTRIBUTION-UNA TTEN 115.12.69.
SCIO DISTRIBUTION-UNA TTEN 69.12.
SEASIDE DISTRIBUTION-UNA TTEN 115.12.47
SELMA DISTRIBUTION-UNA TTEN 115.12.
SHASTAWAY DISTRIBUTION-UNA TTEN 12.
SIMONSO~DISTRIBUTION-UNA TTEN 69.12.
SIMT AG BOOSTER PUMP DISTRIBUTION-UNA TTEN 34.
SMITH RIVER DISTRIBUTION-UNA TTEN 69.12.47
SOUTH DUNES DISTRIBUTION-UNA TTEN 115.12.
SOUTHGATE DISTRIBUTION-UNA TTEN 69.20.
SPRAGUE RIVER DISTRIBUTION-UNA TTEN 69.12.
STARFIRE LUMBER Fit DISTRIBUTION-UNATTEN 20.0.48
STATE STREET DISTRIBUTION-UNA TTEN 115.20.
STAYTON CITY DISTRIBUTION-UNA TTEN 12.47 2.40
STAYTON DISTRIBUTION-UNA TTEN 69.12.47
STEAMBOAT DISTRIBUTION-UNA TTEN 115.
STEVENS ROAD DISTRIBUTION-UNA TTEN 115.20.
STONE FOREST FII DISTRIBUTION-UNATTEN 20.
STRAND BOARD Fit DISTRIBUTION-UNA TTEN 20.0.48
SUTHERLIN DISTRIBUTION-UNA TTEN 115.12.
SWEET HOME DISTRIBUTION-UNA TTEN 115.20.
T AKELMA DISTRIBUTION-UNA TTEN 115.20.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
Increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(1)(9)(h)(i)(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
TALENT DISTRIBUTION-UNA TTEN 69.12.47
TEXUM DISTRIBUTION-UNA TTEN 69.12.
TILLER DISTRIBUTION-UNA TTEN 115.12.47
TOLO DISTRIBUTION-UNA TTEN 69.12.
TWCA RESEARCH FII DISTRIBUTION-UNA TTEN 20.
TWENTY FOURTH STREET FII DISTRIBUTION-UNA TTEN 20.
UMAPINE DISTRIBUTION-UNA TTEN 69.12.
UMATILLA DISTRIBUTION-UNA TTEN 69.12.
US PLYWOOD DISTRIBUTION-UNA TTEN 20.
USBR PUMP FII DISTRIBUTION-UNA TTEN 12.
VERNON DISTRIBUTION-UNA TTEN 69.12.
VILAS DISTRIBUTION-UNA TTEN 115.12.47
VILLAGE GREEN DISTRIBUTION-UNA TTEN 115.20.
VINE STREET DISTRIBUTION-UNA TTEN 46.20.
WALLOWA DISTRIBUTION-UNA TTEN 69.12.
WARM SPRINGS DISTRIBUTION-UNA TTEN 69.20.
W ARRENTON DISTRIBUTION-UNA TTEN 115.12.
WASCO DISTRIBUTION-UNA TTEN 20.
WECOMA BEACH DISTRIBUTION-UNA TTEN 20.
WESTERN KRAFT DISTRIBUTION-UNA TTEN 115.12.47
WESTERN WOOD FII DISTRIBUTION-UNA TTEN 20.0.48
WESTON DISTRIBUTION-UNATTEN 69.12.
WESTSIDE HYDROI DISTRIBUTION-UNA TTEN 69.12.47
WEYERHAUSER DISTRIBUTION-UNA TTEN 69.12.
WHITE CITY DISTRIBUTION-UNA TTEN 115.12.47
WILLAMETTE NATIONAL FII DISTRIBUTION-UNA TTEN 20.
WILLOW COVE DISTRIBUTION-UNA TTEN 34.
WILLOW CREEK DISTRIBUTION-UNA TTEN 69.34.
WINSTON DISTRIBUTION-UNA TTEN 69.12.
YOUNGS BAY DISTRIBUTION-UNA TTEN 115.12.47
Total 16181.2627.195.
NUMBER OF SUBSTATIONS DIST UNATENDED - 218
ALBINA T ID-UNA TTENDED 115.12.69.
APPLEGATE T/D-UNATTENDED 115.69.12.47
ASHLAND T/D-UNA TTENDED 115.69.12.
BEND PLANT T/D-UNA TTENDED 69.12.47
CAVE JUNCTION T/D-UNA TTENDED 115.12.69.
HAZELWOOD T/D-UNATTENDED 115.69.12.47
KNOTT T/D- UNATTENDED 115.12.57.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Me, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)
(j)
(k)
4500 561
177
132
187
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) D A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page , summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
MILE HI T/D-UNA TTENDED 115.69.12.
PILOT BUTTE T/D-UNATTENDED 230.69.12.
WINCHESTER T/D-UNA TTENDED 115.12.47 69.
Total 1219.399.338.
NUMBER OF SUBSTATIONS TID UNATTENDED - 10
CLEARWATER #1 HYDRO PLANT TRANSMISSION-ATTEND 138.
CLEARWATER #2 HYDRO PLANT TRANSMISSION-ATTEND 138.12.
FISH CREEK HYDRO TRANSMISSION-ATTEND 115.
JC BOYLE HYDRO TRANSMISSION-ATTEND 230.11.
LEMOLO #1 HYDRO TRANSMISSION-ATTEND 115.12.
LEMOLO #2 HYDRO TRANSMISSION-ATTEND 115.12.
PROSPECT 1 HYDRO TRANSMISSION-ATTEND 69.
PROSPECT 2 HYDRO TRANSMISSION-ATTEND 69.
PROSPECT 3 HYDRO TRANSMISSION-ATTEND 69.12.
TOKETEE HYDRO TRANSMISSION-ATTEND 115.
Total 1173.89.
NUMBER OF SUBSTATIONS TRANS ATTENDED -
BEND PLANT TRANSMISSION-UNA TTEN
CALAPOOY A TRANSMISSION-UNA TTEN 230.69.
CHILOOUIN TRANSMI SSION-UNA TTEN 230.115.69.
COLD SPRINGS TRANSMISSION-UNA TTEN 230.69.
COVE TRANSMISSION-UNA TTEN 230.69.
DAYS CREEK TRANSMISSION-UNA TTEN 115.69.
DIAMOND HILL TRANSMISSION-UNA TTEN 230.69.
DIXONVILLE 115/230 TRANSMISSION-UNA TTEN 230.115.69.
DJiX
gg~-
TRANSM ISSION-UNA TTEN 500.230.
EAGLE POINT HYDRO TRANSMISSION-UNA TTEN 115.
EAST SIDE HYDRO TRANSMISSION-UNA TTEN 46.12.
FISH HOLE TRANSMISSION-UNA TTEN 115.69.
FRY TRANSMISSION-UNA TTEN 230.115.
GRANTS PASS TRANSMISSION-UNA TTEN 230.115.69.
GREEN SPRINGS PLANTI TRANSMISSION-UNA TTEN 115.69.
HURRICANE TRANSMISSION-UNA TTEN 230.69.
ISTHMUS TRANSMISSION-UNA TTEN 230.115.
KENNEDY TRANSMISSION-UNA TTEN 69.57.
KLAMATH FALLS TRANSMISSION-UNA TTEN 230.69.
LONE PINE TRANSMISSION-UNA TTEN 230.115.69.
MALIN TRANSMISSION-UNA TTEN 500.230.69.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This 'OO'ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
400
1238
343
119
344
650
500
458
250
251
733
775
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
~e~IQr TRANSMISSION-UNA TTEN 500.230.
MONPAC TRANSMISSION-UNA TTEN 115.69.
PONDEROSA TRANSMISSION-UNA TTEN 230.115.
POWERDALE PLANT TRANSMISSION-UNA TTEN 69.
PROSPECT CENTRAL TRANSMISSION-UNA TTEN 115.69.
ROBERTS CREEK TRANSMISSION-UNA TTEN 115.69.
SLIDE CREEK HYDRO TRANSMISSION-UNA TTEN 115.
SODA SPRINGS HYDRO TRANSMISSION-UNA TTEN 115.
TROUTDALE TRANSMISSION-UNA TTEN 230.115.69.
TUCKER TRANSMISSION-UNA TTEN 115.69.
WALLOWA FALLS HYDRO TRANSMISSION-UNA TTEN 20.
Total 6078.2602.47 416.40
NUMBER OF SUBSTATIONS TRANS UNATTEND - 32
Utah
118TH SOUTH DISTRIBUTION-UNA TTEN 138.12.
ALTAVIEW DISTRIBUTION-UNA TTEN 46.12.
AMERICAN FORK DISTRIBUTION-UNA TTEN 138.12.
ANDERSON DISTRIBUTION-UNATTEN 69.12.47
APEX MINE DISTRIBUTION-UNA TTEN 34.
ARAGONITE DISTRIBUTION-UNA TTEN 46.
AURORA DISTRIBUTION-UNA TTEN 46.12.
BANGERTER DISTRIBUTION-UNA TTEN 138.12.47
BEAR RIVER DISTRIBUTION-UNATTEN 46.12.
BENJAMIN DISTRIBUTION-UNA TTEN 46.12.
BINGHAM DlSTRI BUTION-UNA TTEN 46.12.
BLUE CREEK DISTRIBUTION-UNA TTEN 46.12.
BLUFF DISTRIBUTION-UNA TTEN 69.12.
BLUFFDALE DISTRIBUTION-UNA TTEN 46.12.
BOTHWELL DISTRIBUTION-UNATTEN 46.12.47
BOX ELDER DISTRIBUTION-UNATTEN 46.12.
BRIAN HEAD DISTRIBUTION-UNA TTEN 46.12.
BRICKYARD DISTRIBUTION-UNA TTEN 46.12.
BRIGHTON DISTRIBUTION-UNA TTEN 46.24.
BROOKLAWN DISTRIBUTION-UNA TTEN 46.12.
BRUNSWICK DISTRIBUTION-UNA TTEN 46.12.47
BURTON DISTRIBUTION-UNA TTEN 34.12.
BUSH DISTRIBUTION-UNA TTEN 46.12.
CANNON DISTRIBUTION-UNA TTEN 46.12.
CANYONLANDS DISTRIBUTION-UNA TTEN 69.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04125/2005
SU BST A TIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(1)
(g)
(h)(i)(k)
1300
250
500
100
6845
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
CAPITOL DISTRIBUTION-UNA TTEN 46.12.47
CARBIDE DISTRIBUTION-UNA TTEN 46.
CARBONVILLE DISTRIBUTION-UNA TTEN 46.12.
CASTO STATION DISTRIBUTION-UNA TTEN 46.12.
CENTENNIAL DISTRIBUTION-UNA TTEN 138.12.
CENTERVILLE DISTRIBUTION-UNA TTEN 46.12.
CENTRAL DISTRIBUTION-UNA TTEN 46.12.
CHERRYWOOD DISTRIBUTION-UNA TTEN 138.12.
CIRCLEVILLE DISTRIBUTION-UNA TTEN 69.12.
CLEAR LAKE DISTRIBUTION-UNA TTEN 46.12.
CLEARFIELD DISTRIBUTION-UNA TTEN 46.12.
CLINTON DISTRIBUTION-UNA TTEN 138.12.
CLIVE DISTRIBUTION-UNA TTEN 46.12.
COALVILLE DISTRIBUTION-UNA TTEN 46.12.
COLD WATER CANYON DISTRIBUTION-UNA TTEN 138.12.
COLEMAN DISTRIBUTION-UNA TTEN 138.69.12.47
COLTON WELL DISTRIBUTION-UNA TTEN 46.12.47
CORINNE DISTRIBUTION-UNA TTEN 46.12.
COVE FORT DISTRIBUTION-UNA TTEN 46.12.
CRESCENT JUNCTION DISTRIBUTION-UNA TTEN 46.
CROSS HOLLOW DISTRIBUTION-UNA TTEN 138.12.47
CUDAHY DISTRIBUTION-UNA TTEN 138.12.
DAMMERON VALLEY DISTRIBUTION-UNA TTEN 34.12.
DECKER LAKE DISTRIBUTION-UNA TTEN 138.12.
DELLE DISTRIBUTION-UNA TTEN 46.12.
DELTA DISTRIBUTION-UNA TTEN 46.12.
DESERET DISTRIBUTION-UNA TTEN 46.
DEWEYVILLE DISTRIBUTION-UNA TTEN 46.12.47
DIMPLE DELL DISTRIBUTION-UNA TTEN 138.12.
DIXIE DEER DISTRIBUTION-UNA TTEN 34.12.47
DRAGERTON DISTRIBUTION-UNA TTEN 46.12.
DRAPER DISTRI BUTION-UNA TTEN 46.12.47
DUMAS DISTRIBUTION-UNA TTEN 138.12.
EAST BENCH DISTRIBUTION-U NA TTEN 138.12.
EAST HYRUM DISTRIBUTION-UNA TTEN 46.12.
EAST LAYTON DISTRIBUTION-UNA TTEN 138.12.
EAST MILLCREEK DISTRIBUTION-UNA TTEN 46.12.
EDEN DISTRIBUTION-UNA TTEN 46.12.
ELBERTA DISTRIBUTION-UNA TTEN 46.12.
ELK MEADOWS DISTRIBUTION-UNA TTEN 46.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease , and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)
Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(f)
(g)
(In MVa)
(h)(i)(k)
106
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Yea~Period m Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
ELSINORE DISTRIBUTION-UNA TTEN 46.12.
EMERY CITY DISTRIBUTION-UNA TTEN 69.12.
EMIGRATION DISTRIBUTION-UNA TTEN 46.12.
ENOCH DISTRIBUTION-UNA TTEN 138.12.
ENTERPRISE VALLEY DISTRIBUTION-UNA TTEN 138.12.
EUREKA DISTRIBUTION-UNA TTEN 46.12.47
FARMINGTON DISTRIBUTION-UNA TTEN 46.12.
FAYETTE DISTRIBUTION-UNA TTEN 46.12.
FERRON DISTRIBUTION-UNA TTEN 46.12.
FIELDING DISTRIBUTION-UNA TTEN 46.12.
FIFTH WEST DISTRIBUTION-UNA TTEN 138.12.
FLUX DISTRIBUTION-UNA TTEN 46.12.
FOUNTAIN GREEN DISTRIBUTION-UNATTEN 46.12.
FREEDOM STATION DISTRIBUTION-UNA TTEN 46.
FRUIT HEIGHTS DISTRIBUTION-UNA TTEN 46.12.
GATEWAY DISTRIBUTION-UNA TTEN 69.12.
GOSHEN DISTRIBUTION-UNA TTEN 46.12.47
GRANGER DISTRIBUTION-UNA TTEN 46.12.
GRANTSVILLE DISTRIBUTION-UNA TTEN 46.12.
GRAVEL PIT FII DISTRIBUTION-UNA TTEN 46.12.47
GREEN RIVER DISTRIBUTION-UNA TTEN 46.12.
GROW DISTRIBUTION-UNA TTEN 138.12.47 46.
GUNNISON DISTRIBUTION-UNA TTEN 46.12.
HAMILTON DISTRIBUTION-UNA TTEN 34.12.
HAMMER DISTRIBUTION-UNA TTEN 138.12.
HAVASU DISTRIBUTION-UNA TTEN 69.12.
HELPER CITY DISTRI BUTION-U NA TTEN 46.
HENEFER DISTRIBUTION-UNA TTEN 46.12.47
HIAWATHA DISTRIBUTION-UNA TTEN 46.
HIGHLAND DIST DISTRIBUTION-UNA TTEN 46.12.
HOGGARD DISTRIBUTION-UNA TTEN 138.12.47
HOGLE DISTRIBUTION-UNATTEN 46.12.
HOLDEN DISTRI BUTION-U NA TTEN 46.12.47
HOLLADAY DISTRIBUTION-UNA TTEN 46.12.
HUNTER DISTRIBUTION-UNA TTEN 46.12.
HUNTINGTON CITY DISTRIBUTION-UNA TTEN 69.12.
HURRICANE FIELDS DISTRIBUTION-UNA TTEN 34.12.
IRON MOUNTAIN DISTRIBUTION-UNA TTEN 34.
IRON SPRINGS DISTRIBUTION-UNA TTEN 34.12.
IRONTON DISTRIBUTION-UNA TTEN 46.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
ooort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004104
(2) LJ A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units
(f)
(In MVa)
(g)
(h)(i)(k)
FERC FORM NO.1 lED. 12-96)Page 427.
Name of Respondent This 'OO'ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04125/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
IVINS DISTRIBUTION-UNA TTEN 34.12.47
JORDAN NARROWS DISTRIBUTION-UNA TTEN 46.
JORDAN PARK DISTRIBUTION-UNA TTEN 138.12.47
JORDANELLE DISTRIBUTION-UNA TTEN 138.12.
JUAB DISTRIBUTION-UNATTEN 46.12.
JUNCTION DISTRIBUTION-UNA TTEN 69.12.
KAIBAB DISTRIBUTION-UNATTEN 69.12.
KAMAS DISTRIBUTION-UNATTEN 46.12.
KANARRAVILLE DISTRIBUTION-UNA TTEN 34.12.47
KEARNS DISTRIBUTION-UNA TTEN 138.12.47
KENSINGTON DISTRIBUTION-UNA TTEN 46.
LAKEP ARK DISTRIBUTION-UNATTEN 138.12.
LARK DISTRIBUTION-UNA TTEN 46.12.
LASAL DISTRIBUTION-UNATTEN 69.12.47
LAYTON DISTRIBUTION-UNA TTEN 46.12.
LEGRANDE DISTRIBUTION-UNA TTEN 46.12.
LINCOLN DISTRIBUTION-UNA TTEN 46.12.47
LINDON DISTRIBUTION-UNA TTEN 46.12.
LISBON DISTRIBUTION-UNA TTEN 69.12.
LITTLE MOUNTAIN DISTRIBUTION-UNA TTEN 46.12.
LOAFER DISTRIBUTION-UNA TTEN 46.12.47
LONE TREE DISTRIBUTION-UNA TTEN 34.12.
LOWER BEAVER DISTRIBUTION-UNA TTEN 46.
YNNDYL DISTRIBUTION-UNA TTEN 46.12.
MAESER DISTRIBUTION-UNA TTEN 69.12.
MAGNA DISTRIBUTION-UNA TTEN 138.12.
MANILA DISTRIBUTION-UNA TTEN 46.12.
MANTUA DISTRIBUTION-UNA TTEN 46.12.
MAPLETON DISTRIBUTION-UNATTEN 46.12.
MARRIOTT DISTRIBUTION-UNA TTEN 46.12.
MARYSVALE DISTRIBUTION-UNA TTEN 46.12.47
MATHIS DISTRIBUTION-UNA TTEN 46.12.
MCCORNICK DISTRIBUTION-UNA TTEN 46.12.
MCKAY DISTRI BUTION-UNA TTEN 46.12.
MEADOWBROOK DISTRIBUTION-UNA TTEN 138.12.46.
MEDICAL DISTRIBUTION-UNA TTEN 46.12.
MELLING DISTRIBUTION-UNA TTEN 34.
MERRILL DISTRIBUTION-UNA TTEN 69.12.
MIDLAND DISTRIBUTION-UNA TTEN 138.12.47
MIDV ALE DISTRIBUTION-UNA TTEN 46.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This (gprt Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), W, and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.
In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
. 16
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This wrt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale , may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
MILFORD DISTRIBUTION-UNA TTEN 46.12.
MILFORD TV DISTRIBUTION-UNA TTEN 46.
MINERSVILLE DISTRIBUTION-UNA TTEN 46.12.
MOAB CITY DISTRIBUTION-UNA TTEN 69.12.47
MONTEZUMA DISTRIBUTION-UNA TTEN 69.12.
MOORE DISTRIBUTION-UNA TTEN 69.12.
MORGAN DISTRIBUTION-UNA TTEN 46.
MORONI DISTRIBUTION-UNA TTEN 46.12.
MORTON COURT DISTRIBUTION-UNA TTEN 138.12.
MOUNTAIN DELL DISTRIBUTION-UNA TTEN 46.12.
MOUNTAIN GREEN DISTRIBUTION-UNA TTEN 46.12.47
MYTON DISTRIBUTION-UNA TTEN 69.12.47
NEW HARMONY DISTRIBUTION-UNA TTEN 69.12.47
NEWGA TE DISTRI BUTION-U NA TTEN 46.12.
NORTH BENCH DISTRIBUTION-UNA TTEN 46.12.47
NORTH CEDAR DISTRIBUTION-UNA TTEN 34.
NORTH FIELDS DISTRIBUTION-UNA TTEN 46.12.
NORTH OGDEN DISTRIBUTION-UNA TTEN 46.12.47
NORTH SALT LAKE DISTRIBUTION-UNA TTEN 46.12.
NORTHEAST DISTRIBUTION-UNA TTEN 46.12.47
NORTHRIDGE DISTRIBUTION-UNATTEN 46.12.
OAKLAND AVE DISTRIBUTION-UNA TTEN 46.12.47
OAKLEY DISTRIBUTION-UNA TTEN 46.12.
OGDEN DEFENSE DEPOT DISTRI BUTION-U NA TTEN 46.12.
OL YMPUS DISTRIBUTION-UNA TTEN 46.12.47
OPHIR DISTRI BUTION-U NA TTEN 46.12.47
ORANGE DISTRIBUTION-UNA TTEN 46.12.47
ORANGEVILLE DISTRIBUTION-UNA TTEN 69.12.
OREM DISTRIBUTION-UNA TTEN 46.12.
OREMET DISTRIBUTION-UNA TTEN 115.12.47
PACK CREEK RESERVOIR DISTRIBUTION-UNA TTEN 46.12.47
PANGUITCH DISTRIBUTION-UNA TTEN 69.12.
PARlETTE STATION DISTRIBUTION-UNA TTEN 69.24.
PARK CITY DISTRIBUTION-UNA TTEN 46.12.
PARKWAY DISTRIBUTION-UNA TTEN 138.12.47
PARLEYS DISTRIBUTION-UNA TTEN 46.12.
PARRY (NIS)DISTRIBUTION-UNA TTEN 46.
PELICAN POINT DISTRIBUTION-UNA TTEN 46.12.
PINE CANYON DISTRIBUTION-UNA TTEN 132.12.
PINE CREEK DISTRIBUTION-UNA TTEN 46.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04
(2) Li A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), m, and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(i)(k)
13
14 .
16 '
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
PINNACLE DISTRIBUTION-UNA TTEN 46.12.
PLAIN CITY DISTRIBUTION-UNA TTEN 138.12.47
PLEASANT GROVE DISTRIBUTION-UNA TTEN 46.12.47
PLEASANT VIEW DISTRIBUTION-UNA TTEN 46.12.
PROMONTORY DISTRIBUTION-UNA TTEN 46.12.47
~UAiL CREEK DISTRIBUTION-UNA TTEN 34.12.
~UARRY DISTRIBUTION-UNA TTEN 138.12.47
OUITCHAPA DISTRIBUTION-UNATTEN 34.12.
RAINS DlSTRIBUTION-UNATTEN 46.
RASMUSON DISTRIBUTION-UNA TTEN 46.12.47
RATTLESNAKE DISTRIBUTION-UNA TTEN 69.24.
RED MOUNTAIN DISTRIBUTION-UNA TTEN 69.34.
RED ROCK DISTRIBUTION-UNA TTEN 69.
REDWOOD DISTRIBUTION-UNA TTEN 46.12.
RESEARCH PARK DISTRIBUTION-UNA TTEN 46.12.47
RICHFIELD DISTRIBUTION-UNA TTEN 46.12.47
RITER DISTRI BUTION-U NA TTEN 46.12.
ROCK CANYON DISTRIBUTION-UNA TTEN 69.12.
ROCKVILLE DISTRI BUTION-U NA TTEN 34.12.47
ROCKY POINT DISTRIBUTION-UNA TTEN 138.13.
ROSE PARK DISTRIBUTION-UNA TTEN 46.12.47
ROYAL DISTRIBUTION-UNA TTEN 46.
SALINA DISTRIBUTION-UNA TTEN 46.12.47
SANDY DISTRIBUTION-UNA TTEN 138.12.
SARATOGA DISTRIBUTION-UNA TTEN 138.12.47
SCIPIO DISTRIBUTION-UNA TTEN 46.12.
SCOFIELD RESERVOIR DISTRIBUTION-UNA TTEN 46.
SCOFIELD DISTRIBUTION-UNA TTEN 46.12.47
SECOND STREET DISTRIBUTION-UNA TTEN 46.12.
SEVEN MILE DISTRIBUTION-UNA TTEN 46.12.47
SHARON DISTRIBUTION-UNA TTEN 46.12.
SHIVWITS DISTRIBUTION-UNA TTEN 34.
SIXTH SOUTH DISTRIBUTION-UNA TTEN 46.12.
SKULL POINT DISTRIBUTION-UNA TTEN 46.12.
SNARR DISTRIBUTION-UNA TTEN 46.12.
SNOWVILLE DISTRIBUTION-UNA TTEN 69.12.
SNYDERVILLE DISTRIBUTION-UNA TTEN 138.12.
SOLDIER SUMMIT DISTRIBUTION-UNATTEN 69.12.
SOUTH JORDAN DISTRIBUTION-UNA TTEN 138.12.47
SOUTH MILFORD DISTRIBUTION-UNA TTEN 46.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (1),0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)
(j)
(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
SOUTH MOUNTAIN DISTRIBUTION-UNA TTEN 138.12.
SOUTH OGDEN DISTRIBUTION-UNATTEN 46.12.
SOUTH PARK DISTRIBUTION-UNATTEN 46.12.
SOUTH YARD DISTRIBUTION-UNATTEN 46.
SOUTH EAST DISTRIBUTION-UNA TTEN 46.
SOUTHW EST DISTRIBUTION-UNA TTEN 46.12.
SPANISH VALLEY DISTRIBUTION-UNA TTEN 69.12.
SPRINGDALE DISTRIBUTION-UNA TTEN 34.12.
ST. JOHNS DISTRIBUTION-UNA TTEN 46.12.
STAIRS DISTRIBUTION-UNA TTEN 12.
STANSBURY DISTRIBUTION-UNA TTEN 46.12.
SUMMIT CREEK DISTRIBUTION-UNA TTEN 138.12.
SUMMIT PARK DISTRIBUTION-UNA TTEN 46.12.
SUNRISE DISTRIBUTION-UNA TTEN 138.12.47
SUPERIOR DISTRIBUTION-UNA TTEN 69.12.
SUTHERLAND DISTRIBUTION-UNA TTEN 46.12.47
SWISS DISTRIBUTION-UNA TTEN 46.
T ABIONA DISTRIBUTION-UNATTEN 69.12.47
TAYLOR DISTRIBUTION-UNA TTEN 46.12.47
THIEF CREEK DISTRIBUTION-UNA TTEN 138.24.
THIRD WEST DISTRIBUTION-UNA TTEN 46.12.
THIRTEENTH SOUTH DISTRIBUTION-UNA TTEN 46.12.
THOMPSON DISTRIBUTION-UNATTEN 46.
TOOUERVILLE DISTRIBUTION-UNA TTEN 69.12.34.
TRI CITY DISTRIBUTION-UNA TTEN 138.12.
TWENTYTHIRD STREET DISTRIBUTION-UNA TTEN 46.12.
UINT AH DISTRIBUTION-UNA TTEN 46.12.
UNION DISTRIBUTION-UNA TTEN 46.12.47
UNIVERSITY DISTRIBUTION-UNA TTEN 46.
UTE STATION DISTRIBUTION-UNA TTEN 69.
VALLEY CENTER DISTRIBUTION-UNA TTEN 46.12.
VERMILLION DISTRIBUTION-UNA TTEN 46.12.
VERNAL DISTRIBUTION-UNA TTEN 69.12.
VEYO HYDRO DISTRIBUTION-UNA TTEN 34.2.40
VICKERS DISTRIBUTION-UNA TTEN 46.12.47
VINEYARD DISTRIBUTION-UNA TTEN 46.12.
W ALFARE DISTRIBUTION-UNA TTEN 46.12.
WALLSBURG DISTRIBUTION-UNA TTEN 138.12.
WARREN DISTRIBUTION-UNA TTEN 138.12.
WASATCH DISTRIBUTION-UNA TTEN 46.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(1)
(g)
(h)(i)(k)
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
ooort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
WASHAKIE DISTRIBUTION-UNA TTEN 138.
WELBY DISTRIBUTION-UNA TTEN 46.12.
WELCH DISTRIBUTION-UNATTEN 57.
WELLINGTON DISTRIBUTION-UNA TTEN 46.12.
WEST COMMERCIAL DISTRIBUTION-UNA TTEN 46.12.47
W EST JORDAN DISTRIBUTION-UNA TTEN 138.12.
WEST OGDEN DISTRIBUTION-UNA TTEN 138.12.
WEST ROY DISTRIBUTION-UNA TTEN 46.12.47
WEST TEMPLE DISTRIBUTION-UNA TTEN 46.
WESTFIELD DISTRIBUTION-UNA TTEN 138.12.47
WESTWATER DISTRIBUTION-UNA TTEN 69.12.
WHITE MESA DISTRIBUTION-UNA TTEN 69.12.47
WILLOWCREEK DISTRIBUTION-UNA TTEN 46.12.
WILLOWRIDGE DISTRIBUTION-UNA TTEN 46.12.
WINCHESTER HILLS DISTRIBUTION-UNATTEN 34.12.
WINKLEMAN DISTRIBUTION-UNA TTEN 46.
WOLF CREEK DISTRIBUTION-UNA TTEN 69.12.47
WOOD CROSS DISTRIBUTION-UNA TTEN 46.12.
WYUT A DISTRI BUTION-U NA TTEN 46.12.
Total 18233.3416.138.
NUMBER OF SUBSTATIONS DIST UNATTENDED - 284
ANGEL \T/D-UNA TTENDED 138.12.46.
BUTLERVJLLE T ID-UNA TTENDED 138.46.12.
COTTONWOOD T/D-UNATTENDED 138.12.46.
HALE T/D-UNA TTENDED 138.46.12.47
HIGHLAND T/D-UNA TTENDED 138.12.46.
JORDAN T/D-UNATTENDED 138.46.12.
JUDGE T/D-UNATTENDED 46.12.
MCCLELLAND T/D-UNATTENDED 138.46.12.47
O~UiRRH T/D-UNATTENDED 138.46.12.
PARRISH T/D-UNATTENDED 138.12.46.
PIONEER PLANT T ID-UNA TTENDED 138.46.
RIVERDALE T/D-UNATTENDED 138.46.12.
SEVIER T ID-UNA TTENDED 138.46.12.
SILVER CREEK T/D-UNA TTENDED 138.12.46.
SPHINX T/D-UNATTENDED 46.12.47
SYRACUSE T/D-UNATTENDED 138.46.12.
T A YLORSVILLE T ID-UNA TTENDED 138.46.12.47
TERMINAL T ID-UNA TTENDED 345.12.46.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), W, and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
4753 428
135
175
289
114
164
340
135
180
100
200
358
1108
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04
(2) LJ A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
TIMP T/D-UNA TTENDED 138.46.12.47
TOOELE T/D-UNA TTENDED 138.46.12.
WEST VALLEY T/D-UNATTENDED 138.12.47
Total 2921.620.459.
NUMBER OF SUBSTATIONS TID UNATTENDED - 21
BLUNDELL PLANT TRANSMISSION-ATTEND 46.12.
CARBON PLANT TRANSMISSION-ATTEND 138.13.
EMERY TRANSMISSION-ATTEND 138.69.
GADSBY PLANT TRANSMISSION-ATTEND 138.13.46.
GADSBY TRANSMISSION-ATTEND 138.46.
HUNTER PLANT TRANSMISSION-ATTEND 345.23.
HUNTINGTON PLANT TRANSMISSION-ATTEND 345.23.
Total 1288.138.115.
NUMBER OF SUBSTATIONS TRANS ATTENDED - 7
90TH SOUTH TRANSMISSION-UNA TTEN 345.138.
ABAJO TRANSMISSION-UNA TTEN 138.69.
ASHLEY TRANSMISSION-UNA TTEN 138.46.
BARNEY TRANSMISSION-UNA TTEN 138.46.
BEN LOMOND TRANSMISSION-UNA TTEN 345.230.138.
BLACKHAWK TRANSMISSION-UNA TTEN 138.69.46.
BOOKCLIFFS TRANSMISSION-UNA TTEN 69.46.
CAMERON TRANSMISSION-UNA TTEN 138.46.
CAMP WILLIAMS TRANSMISSION-UNA TTEN 345.138.12.47
CARBON TRANSMISSION-UNA TTEN 46.
COLUMBIA TRANSMISSION-UNA TTEN 138.46.
CRICKET MOUNTAIN REG STA TRANSMISSION-UNA TTEN 46.46.
CUTLER TRANSMISSION-UNA TTEN 138.46.
EL MONTE TRANSMI SSION-U NA TTEN 138.46.
GARKANE TRANSMISSION-UNA TTEN 69.46.
GRINDING TRANSMISSION-UNA TTEN 138.13.
HELPER TRANSMISSION-UNA TTEN 138.46.
HONEYVILLE TRANSMISSION-UNA TTEN 138.46.
HORSESHOE TRANSMISSION-UNA TTEN 138.46.12.
HUNTINGTON CANYON TRANSMISSION-UNA TTEN 345.138.69.
JERUSALEM TRANSMISSION-UNA TTEN 138.46.
LAMPO TRANSMISSION-UNA TTEN 138.46.
MCFADDEN TRANSMISSION-UNA TTEN 138.46.
MIDDLETON TRANSMISSION-UNA TTEN 138.69.34.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2004/04(2) n A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others , jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.
In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
130
158
3912
225
783
568
318
1513
981
4413
1538
133
100
1813
100
169
313
225
142
270
141
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
MIDVALLEY TRANSMISSION-UNA TTEN 345.138.
MIDWAY CITY TRANSMISSION-UNA TTEN 138.46.
MINERAL PRODUCTS TRANSMISSION-UNA TTEN 69.46.
MOAB TRANSMISSION-UNA TTEN 138.69.
NEBO TRANSMISSION-UNA TTEN 138.46.
OLMSTED TRANSMISSION-UNA TTEN 46.2.40
PAROW AN VALLEY TRANSMISSION-UNA TTEN 230.138.34.
PAVANT TRANSMISSION-UNA TTEN 230.46.
PINTO TRANSMISSION-UNA TTEN 345.138.69.
RED BUTTE TRANSMISSION-UNA TTEN 230.138.
SAND COVE HYDRO TRANSMISSION-UNA TTEN 34.2.40
SCOVILLE TRANSMISSION-UNA TTEN 138.69.46.
SIGURD TRANSMISSION-UNA TTEN 345.230.138.
SPANISH FORK TRANSMISSION-UNA TTEN 345.138.46.
UPPER BEAVER HYDRO TRANSMISSION-UNA TTEN 46.
WEBER PLANTI TRANSMISSION-UNA TTEN 46.
WEST CEDAR TRANSMISSION-UNA TTEN 230.138.34.
Total 6911.2946.680.
NUMBER OF SUBSTATIONS TRANS UNATTENDED - 41
Washington
ATTALIA DISTRIBUTION-UNA TTEN 69.12.47
BOWMAN DISTRIBUTION-UNA TTEN 69.12.
CASCADE KRAFT DISTRIBUTION-UNA TTEN 69.12.
CLINTON DISTRIBUTION-UNA TTEN 115.12.
DAYTON DISTRIBUTION-UNA TTEN 69.12.
DODD ROAD DISTRIBUTION-UNA TTEN 69.20.
GRANDVIEW DISTRIBUTION-UNA TTEN 115.12.47 69.
HOPLAND DISTRIBUTION-UNA TTEN 115.12.47
MILL CREEK DISTRIBUTION-UNA TTEN 69.12.
NACHES HYDRO DISTRIBUTION-UNA TTEN 115.12.
NOB HILL DISTRIBUTION-UNA TTEN 115.12.
NORTH PARK DISTRI BUTION-UNA TTEN 115.12.47
ORCHARD DISTRI BUTION-UNA TTEN 115.12.
PACIFIC DISTRIBUTION-UNA TTEN 115.12.47
POMEROY DISTRIBUTION-UNA TTEN 69.12.47
PROSPECT POINT DISTRIBUTION-UNA TTEN 69.12.47
PUNKIN CENTER DISTRIBUTION-UNA TTEN 115.12.
RIVER ROAD DISTRIBUTION-UNA TTEN 115.12.47
SELAH DISTRIBUTION-UNA TTEN 115.12.47
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This wrt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT . Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
900
138
133
258
400
1124
1017
131
9922
117
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
SULPHUR CREEK DISTRIBUTION-UNA TTEN 115.12.
SUNNYSIDE DISTRIBUTION-UNA TTEN 115.12.47
TIETON DISTRIBUTION-UNA TTEN 115.12.47 34.
TOPPENISH DISTRIBUTION-UNA TTEN 115.12.47
TOUCHET DISTRIBUTION-UNA TTEN 69.12.47
VOELKER DISTRIBUTION-UNA TTEN 115.12.
W AITSBURG DISTRIBUTION-UNA TTEN 69.12.47
WAPATO DISTRIBUTION-UNA TTEN 115.12.
WENAS DISTRIBUTION-UNA TTEN 115.12.47
WHITE SWAN DISTRI BUTION-U NA TTEN 115.12.47
WILEY DISTRIBUTION-UNA TTEN 115.12.47
Total 2990.382.43 107.
NUMBER OF SUBSTATIONS DIST UNATTENDED - 30
CENTRAL T/D-UNATTENDED 69.12.
UNION GAP T ID-UNA TTENDED 230.115.12.
Total 299.127.47 12.
NUMBER OF SUBSTATIONS TID UNATTENDED - 2
CONDIT PLANT TRANSMISSION-ATTEND 69.
MERWIN PLANT TRANSMISSION-ATTEND 115.13.
Total 184.15.
NUMBER OF SUBSTATIONS TRANS ATTENDED - 2
OUTLOOK TRANSMISSION-UNA TTEN 230.115.
PASCO TRANSMISSION-UNA TTEN 115.69.
POMONA HEIGHTS TRANSMISSION-UNA TTEN 230.115.
SWIFT 1 PLANT TRANSMISSION-UNA TTEN 230.13.
WALLA WALLA 230KV TRANSMISSION-UNA TTEN 230.69.
WALLULA TRANSMISSION-UNA TTEN 230.69.
YALE PLANT TRANSMISSION-UNA TTEN 115.13.
Total 1380.463.
NUMBER OF SUBSTATIONS TRANS UNATTENDED - 7
Wyoming
AIR BASE DISTRIBUTION-UNA TTEN 12.47 2.40
AMOCO SERVICE PIPE DISTRIBUTION-UNA TTEN 34.
ANTELOPE MINE DISTRIBUTION-UNA TTEN 230.34.
ASTLE STREET DISTRIBUTION-UNA TTEN 34.13.
BAILEY DOME DISTRIBUTION-UNA TTEN 57.12.47
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
1071
348
362
183
196
125
300
261
300
120
144
1289
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004104(2) 0 A Resubmission 04125/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
Name and Location of Substation Character of SubstationNo.Primary Secondary Tertiary
(a)(b)(c)(d)(e)
BAR X DISTRIBUTION-UNA TTEN 230.34.
BATTLE SPRINGS FII DISTRIBUTION-UNA TTEN 34.
BELLAMY DISTRIBUTION-UNA TTEN 57.12.47
BID MUDDY DISTRIBUTION-UNA TTEN 69.12.
BIG PINEY DISTRIBUTION-UNA TTEN 69.24.
BLACKS FORK DISTRIBUTION-UNA TTEN 230.34.
BRIDGER PUMP DISTRIBUTION-UNA TTEN 230.34.13.
BRYAN DISTRIBUTION-UNA TTEN 115.12.
BUFFALO TOWN DISTRIBUTION-UNATTEN 20.
BYRON DISTRIBUTION-UNA TTEN 34.
CASSA DISTRIBUTION-UNA TTEN 57.20.
CENTER STREET DISTRIBUTION-UNA TTEN 115.
CHAPMAN STATION DISTRIBUTION-UNA TTEN 46.12.
CHATHAM DISTRIBUTION-UNA TTEN 34.
CHUKAR DISTRIBUTION-UNA TTEN 12.47
CHURCH AND DWIGHT DISTRIBUTION-UNA TTEN 34.
COKEVILLE DISTRIBUTION-UNA TTEN 46.24.
COLUMBIA-GENEVA DISTRIBUTION-UNA TTEN 230.13.
COMMUNITY PARK DISTRIBUTION-UNA TTEN 69.12.
CONTINENTAL PIPELINE FII DISTRIBUTION-UNA TTEN 12.
CROOKS GAP DISTRIBUTION-UNA TTEN 34.12.
DEAVER TOWN DISTRIBUTION-UNA TTEN 34.
DEER CREEK DISTRIBUTION-UNA TTEN 69.12.
DJ COAL MINE DISTRIBUTION-UNA TTEN 69.34.
DOUGLAS DISTRIBUTION-UNA TTEN 57.
DRY FORK DISTRIBUTION-UNA TTEN 69.
ELK BASIN DISTRIBUTION-UNA TTEN 34.
EMIGRANT DISTRIBUTION-UNATTEN 115.12.
EVANS DISTRIBUTION-UNA TTEN 69.12.47
EVANSTON DISTRIBUTION-UNA TTEN 138.12.
FARMERS UNION DISTRIBUTION-UNA TTEN 34.
FIREHOLE DISTRIBUTION-UNA TTEN 230.34.
FMC PLANT #1-FII DISTRIBUTION-UNA TTEN
FMC PLANT #2-FII DISTRIBUTION-UNA TTEN
FORT CASPER DISTRIBUTION-UNATTEN 69.12.
FORT SANDERS DISTRIBUTION-UNATTEN 115.13.
FRANNIE DISTRIBUTION-UNA TTEN 230.34.
FRONTIER DISTRIBUTION-UNA TTEN 69.
GARDEN CITY DISTRIBUTION-UNA TTEN 46.12.47
GARLAND DISTRIBUTION-UNA TTEN 230.34.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04
(2) D A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
150
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent 1hls
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2004/04(2) r=; A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
GLENDO DISTRIBUTION-UNATTEN 57.
GRASS CREEK DISTRI BUTI ON-U NA TTEN 230.34.
GREAT DIVIDE DISTRIBUTION-UNA TTEN 115.34.
GREYBULL DISTRIBUTION-UNA TTEN 34.
HANNA DISTRIBUTION-UNA TTEN 34.12.
JACKALOPE DISTRIBUTION-UNA TTEN 115.12.47
KEMMERER DISTRIBUTION-UNA TTEN 69.24.
KIRBY CREEK PUMPING STATION DISTRIBUTION-UNA TTEN 34.2.40
KIRBY CREEK DISTRIBUTION-UNA TTEN 34.
LANDER DISTRIBUTION-UNA TTEN 34.12.47
LARAMIE DISTRIBUTION-UNA TTEN 115.13.
LINCH DISTRIBUTION-UNATTEN 69.13.
LITTLE MOUNTAIN DISTRIBUTION-UNA TTEN 230.34.
LOVELL DISTRIBUTION-UNA TTEN 34.
MANDERSON DISTRIBUTION-UNA TTEN 34.
MIDWEST HEIGHTS Fit DISTRIBUTION-UNA TTEN 69.
MILL IRON DISTRIBUTION-UNA TTEN 34.13.
MILLS DISTRIBUTION-UNATTEN 12.47
MOSS JUNCTION DlSTRI BUTION-UNA TTEN 46.12.47
MOUNTAIN GAS-FII DISTRI BUTION-UNA TTEN 34.
MURPHY DOME DISTRIBUTION-UNA TTEN 34.13.
NORTH BAXTER -FII DISTRIBUTION-UNATTEN 34.
NUGGETT DISTRIBUTION-UNA TTEN 69.
OPAL DISTRIBUTION-UNATTEN 46.24.
ORIN DISTRIBUTION-UNA TTEN 57.12.
ORPHA DISTRIBUTION-UNA TTEN 57.
OVERLAND TRAIL -FII DISTRIBUTION-UNA TTEN
OWL CREEK -Fit DISTRIBUTION-UNA TTEN 34.
PARCO DISTRIBUTION-UNA TTEN 34.12.
PINEDALE DISTRIBUTION-UNA TTEN 69.24.
PITCHFORK DISTRIBUTION-UNA TTEN 69.24.
PLATTE PIPE BRYON FII DlSTRI BUTION-U NA TTEN 34.
PLATTE PIPE OREGON BASIN-FII DISTRIBUTION-UNA TTEN 34.
PLATTE RIVER DJ-FII DISTRIBUTION-UNA TTEN 69.12.
POINT OF ROCKS DISTRIBUTION-UNA TTEN 230.34.
POISON SPIDER DISTRIBUTION-UNA TTEN 69.
POLECAT DISTRIBUTION-UNA TTEN 34.12.47
RAINBOW DISTRIBUTION-UNA TTEN 34.13.
RAVEN DISTRIBUTION-UNA TTEN 230.34.
RED BUTTE DISTRIBUTION-UNA TTEN 69.12.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo. Da, Yr)End of 2004/04
(2) D A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
200
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation , designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
REFINERY DISTRIBUTION-UNA TTEN 115.12.
ROCK SPRINGS 34.5KV DISTRIBUTION-UNA TTEN 34.13.
SAGE HILL DISTRI BUTION-U NA TTEN 34.13.
SHOSHONI DISTRIBUTION-UNA TTEN 34.
SINCLAIR PIPELINE FII DISTRIBUTION-UNATTEN 34.
SLATE CREEK DISTRIBUTION-UNA TTEN 69.12.
SOUTH CODY DISTRIBUTION-UNATTEN 69.24.
SOUTH ELK BASIN DISTRIBUTION-UNA TTEN 34.
SOUTH TRONA DISTRI BUTION-UNA TTEN 230.34.
SPRING CREEK DISTRIBUTION-UNA TTEN 115.13.
SVILAR DISTRIBUTION-UNA TTEN 34.
TEAPOT DISTRIBUTION-UNA TTEN 69.12.47
TEN MILE DISTRIBUTION-UNA TTEN 69.34.
THERMOPOLIS TOWN DISTRIBUTION-UNA TTEN 34.
THUNDER CREEK DISTRIBUTION-UNA TTEN 57.12.
TIPTON FII DISTRI BUTION-UNA TTEN 34.
VETERANS DISTRIBUTION-UNA TTEN 34.13.
WARM SPRINGS SPL-FII DISTRIBUTION-UNA TTEN 115.
WEST ADAMS DISTRIBUTION-UNA TTEN 34.
WESTERN CLAY DISTRIBUTION-UNA TTEN 34.
WESTVACO DISTRIBUTION-UNA TTEN 230.34.
WOODRUFF DISTRIBUTION-UNA TTEN 46.12.
WORLAND TOWN DISTRI BUTION-UNA TTEN 34.
WYCO PIPELINE FII DISTRIBUTION-UNA TTEN 12.
Total 8186.1408.13.
NUMBER OF SUBSTATIONS DIST UNATTENDED-109
LABARGE T ID-UNA TTENDED 69.24.
BUFFALO T/D-UNATTENDED 230.20.
HILLTOP T/D-UNA TTENDED 115.34.20.
RIVERTON 230 T/D-UNA TTENDED 230.12.34.
YELLOWCAKE T/D-UNA TTENDED 230.34.
Total 874.127.55.
NUMBER OF SUBSTATIONS TID UNATTENDED - 5
DAVE JOHNSTON 69KV TRANSMISSION-ATTEND 115.2.40 69.
DAVE JOHNSTON PLANTI TRANSMISSION-ATTEND 230.115.69.
JIM BRIDGER 345KV TRANSMISSION-ATTEND 345.230.34.
JIM BRIDGER UNITS 1 &2 TRANSMISSION-ATTEND 345.22.
JIM BRIDGER UNITS 3&4 TRANSMISSION-ATTEND 345.22.
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), G). and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Type of Equipment Total Capacity No.In Service Transformers Number of Units (In MVa)
(f)
(g)
(h)(i)(k)
150
1683 204
148
214
1358
1084
1122
1122
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation , designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation
Primary Secondary Tertiary
(a)(b)(c)(d)(e)
NAUGHTON TRANSMISSION-ATTEND 230.69.
WYODAK 230KV TRANSMISSION-ATTEND 230.69.
WYODAK PLANT TRANSMISSION-ATTEND 230.22.
Total 2070.551.172.
NUMBER OF SUBSTATIONS TRANS ATTENDED - 8
BAIROIL TRANSM I SSION-UNA TTEN 115.34.57.
CASPER TRANSMISSION-UNA TTEN 230.115.69.
CHAPPELL CREEK TRANSMISSION-UNA TTEN 230.69.
FOOTE CREEK WIND FARM TRANSMISSION-UNA TTEN 230.34.
GLENDO AUTO TRANSMISSION-UNA TTEN 69.57.
MANSFACE TRANSMISSION-UNA TTEN 230.34.
MIDWEST TRANSMISSION-UNA TTEN 230.69.34.
MINERS TRANSMISSION-UNA TTEN 230.115.34.
MUSTANG TRANSMISSION-UNA TTEN 230.115.
OREGON BASIN TRANSMISSION-UNA TTEN 230.34.69.
PLATTE TRANSMISSION-UNA TTEN 230.115.34.
RAILROAD TRANSMISSION-UNA TTEN 230.138.
ROCK SPRINGS 230 TRANSMISSION-UNA TTEN 230.34.
SAGE TRANSMISSION-UNA TTEN 69.46.
THERMOPOLIS TRANSMISSION-UNA TTEN 230.115.
WYOPO TRANSMISSION-UNA TTEN 230.34.
YELLOWT AIL TRANSMISSION-UNA TTEN 230.16.
Total 3473.1177.298.
NUMBER OF SUBSTATIONS TRANS UNATTENDED -
CALIFORNIA
Distribution - 34
T/D - 3
Transmission - 9
IDAHO
Distribution - 75
TID - 4
Transmission - 20
OREGON
Distribution - 218
TID - 10
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) 0 A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.In Service Transformers Type of Equipment Number of Units (In ~)va)
(f)
(g)
(h)(i)
1232
503
6695
529
196
200
115
165
400
175
100
2301
240
129
446
835
314
2761
4500 218
1238
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2004/04(2) D A Resubmission 04/25/2005
SUBSTATIONS
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Line VOLTAGE (In MVa)
No.Name and Location of Substation Character of Substation Primary Secondary Tertiary
(a)(b)(c)(d)(e)
Transmission - 42
UTAH
Distribution - 284
TID - 21
Transmission - 48
WASHINGTON
Distribution - 30
TID - 2
Transmission - 9
WYOMING
Distribution - 109
T/D - 5
Transmission - 25
ALL STATES
Distribution - 750
T/D - 45
Transmission - 153
FERC FORM NO.1 (ED. 12-96)Page 426.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp
(1) X An Original (Mo, Da, Yr)End of 2004/04
(2) Fi A Resubmission 04/25/2005
SUBSTATIONS (Continued)
5. Show in columns (I), 0), and (k) special equipment such as rotary converters, rectifiers, condensers, etc.and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
Capacity of Substation Number of Number of CONVERSION APPARATUS AND SPECIAL EOUIPMENT Line
(In Service) (In MVa)Transformers Spare Total Capacity No.
In Service Transformers Type of Equipment Number of Units
(f)
(In MVa)
(g)
(h)(i)(k)
7188
4753 284
3912
14335
1071
362
1485
1683 106
148
8996
13082 747
6103
35211 153
FERC FORM NO.1 (ED. 12-96)Page 427.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmisslon 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 103 Line No.Column:
On Ma 4, 2000, the assets of Centralia Mining Com any were sold to TransAlta.
Schedule Page: 103 Line No.Column:
Idaho Power holds a 33.34% ownershi interest in Bridger Coal Com any.
Schedule Page: 103 Line No.Column:
CH2MHill holds a 10.10% ownership interest in PacifiCorp Environmental Remediation Com any.
Schedule Page: 103 Line No.Column:
PacifiCorp Future Generations owns an interest in Canopy Botanicals, Inc., which holds an interest in Canopy Botanicals, SRL relating
to rain forest carbon emissions credits.
I FERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 104 Line No.Column: c
PacifiCorp sets forth the salary information for its five most highly compensated officers for the year ended December 31, 2004
consistent with Item 402 of Regulation S-K as promulgated by the Securities and Exchange Commission. Salary information of other
officers will be provided to the Commission upon request, but the company considers such information personal and confidential to
such officers. See 18 CFR 388.107(d), (t).
ISchedule Page: 104 Line No.Column: c
See footnote for a e 104 line 2, column C.
Schedule Page: 104 Line No.Column: c
See footnote for a e 104 line 2, column C.
Schedule Pa e: 104 Line No.Column: b
A. Richard Wal'e elected Executive Vice President on 04/01/04.
Schedule Pa e: 104 Line No.Column: c
See footnote for page 104 line 2, column C.
ISchedule Page: 104 Line No.11 Column: c
See footnote for a e 104 line 2, column C.
Schedule Pa e: 104 Line No.15 Column: b
William D. Landels retired on 03/31/04.
ISchedule Page: 104 Line No.23 Column: b
Robert A. Moir retired on 03/12/04.
jSchedule Page: 104 Line No.27 Column: b
Jeffrey K. Larsen resigned as Vice President on 09/10/04.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
'Schedule Page: 105 Line No.Column:
William D. Landels retired on 03/31/04.
\Schedu/e Page: 105 Line No.24 Column:
A. Richard Walje elected Executive Vice President on 04/01/2004.
IFERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
'Schedule Page: 110 Line No.Column: c
ISchedule Page: 110 Line No.57 Column:
Of the 71.9 million dollar balance in account 165 Prepayments, 41.9 million represents prepaid income taxes for the period ending
December 31, 2004 aid to PacifiCo Holdin s, Inc. ("PHI"), the arent com an of PacifiCo
Schedule Pa e: 110 Line No.82 Column: c
'Schedule Page: 110 Line No.82 Column:
In 2004, PacifiCorp preformed a study on the accumulated deferred income tax balances. As a result of this study, PacifiCorp adopted
a uniform accounting methodology for accumulated deferred income taxes for both FERC and SEC reporting purposes. For FERC
reporting purposes, some reclassifications were made between accumulated deferred income tax assets account 190 and accumulated
deferred income tax liability accounts 282 and 283 (net/gross presentation). The reclassification had a balance sheet only effect. If the
results of the deferred tax study had been applied to calendar year 2003 the ending accumulated deferred income tax liabilities in
account 190 for CY 2003 would have been approximately $844 607 900.
IFERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
'Schedule Page: 112 Line No.Column: c
'Schedule Page: 112 Line No.63 Column:
In 2004, PacifiCorp preformed a study on the accumulated deferred income tax balances. As a result of this study, PacifiCorp adopted
a uniform accounting methodology for accumulated deferred income taxes for both FERC and SEC reporting purposes. For FERC
reporting purposes, some reclassifications were made between accumulated deferred income tax assets account 190 and accumulated
deferred income tax liability accounts 282 and 283 (net/gross presentation). The reclassification had a balance sheet only effect. If the
results of the deferred tax study had been applied to calendar year 2003 the ending accumulated deferred income tax liabilities in
account 282 for CY 2003 would have been approximately $1,884,198,440.
'Schedule Page: 112 Line No.64 Column: c
ISchedule Page: 112 Line No.64 Column:
In 2004, PacifiCorp preformed a study on the accumulated deferred income tax balances. As a result of this study, PacifiCorp adopted
a uniform accounting methodology for accumulated deferred income taxes for both FERC and SEC reporting purposes. For FERC
reporting purposes, some reclassifications were made between accumulated deferred income tax assets account 190 and accumulated
deferred income tax liability accounts 282 and 283 (net/gross presentation). The reclassification had a balance sheet only effect. If the
results of the deferred tax study had been applied to calendar year 2003 the ending accumulated deferred income tax liabilities in
account 283 for CY 2003 would have been approximately $493,772,249.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 114 Line No.Column: g
In July 2003, the Emerging Issues Task Force ("EITF') issued EITF No. 03-11. Effective January 1,2004, PacifiCorp adopted EITF
No. 03-, which provides guidance on whether to report realized gains or losses on physically settled derivative contracts not held for
trading purposes on a gross or net basis and requires realized gains or losses on derivative contracts that do not settle physically to be
reported on a net basis. The adoption of EITF No. 03-11 resulted in PacifiCorp s netting certain contracts that were previously
recorded on a gross basis, which reduced Sales for Resale and Purchased Power. Since PacifiCorp has a fiscal year end of March 31,
the implementation ofEITF 03-11 resulted in a reclassification of$397.7 million at March 31, 2004 for the fiscal year then ended (first
quarter of the calendar year). Consequently, since FERC reporting is based on a calendar year, the financial information reported
the following accounts contains the impact of the adjustment for the 12 month period ending March 31, 2004 as opposed to just the 3
months impact. The following table summarizes the effect of adopting EITF 03-11 on each quarter of the fiscal year ended March 31,
2004, which was all recorded in the first quarter of the calendar year (fourth quarter of the fiscal year). Adoption of EITF No. 03-
had no impact on PacifiCorp s Net income.
Sales for Resale
Purchased Power
Other Electric Revenues
QI-FY 04 Q2-FY 04 Q3-FY 04
(Q2-CY 03) (Q3-CY 03) (Q4-CY 03)
$113,426,335 $ 82 874 255 $108,970,755
(110,706,073) (104,699,500) (90,471,134)
(2,720,262) 21,825,245 (18,499,621)
Q4- FY 04
CY 04
$98 740,774
(91,782,690)
(6,958,084)
FY 2004 Total
$404,012 119
(397,659,397)
(6,352,722)
ISchedule Page: 114 Line No.Column: g
See footnote on Pa e 114, Line 2, Column G
Schedule Pa e: 114 Line No.Column:
Vehicle de reciation ex ense is allocated to the same account as the labor costs it is associated with.
Schedule Pa e: 114 Line No.14 Column: c
Reconciliation to Page 262-263 Taxes Accrued, Prepaid, and Charged During the Year.
Page 262-263, Line 41 - Total Taxes Charged to Accounts 408.1 & 409.125,762,146
Statement of Income for the Year, Page 114, line 14
Statement of Income for the Year, Page 114, line 15
Statement of Income for the Year, Page 114, line 16
92,915,793
45,160,095
12.313.742
125,762,146
'Schedule Page: 114 Line No.14 Column: g
Payroll tax costs are allocated to the same account as the labor costs they are associated with.
'Schedule Page: 114 Line No.15 Column:
See Footnote on Line 14, Column C
'Schedule Page: 114 Line No.16 Column:
See Footnote on Line 14, Column C
'Schedule Page: 114 Line No.17 Column: g
PacifiCorp keeps its accounting records on a fiscal year basis for Securities Exchange Commission (SEC) financial reporting purposes.
The fiscal year end is March 31 st. Annual fiscal year-end tax adjustments are performed in March. These adjustments result in larger
changes to various tax accounts between "current year end of quarter balances" and "prior year end balances" in the first quarter FERC
3-Q (first quarter of the calendar year) report than in subsequent uarters.
Schedule Page: 114 Line No.18 Column: g
See footnote on Pa e 114, Line 17, Column G.
Schedule Pa e: 114 Line No.55 Column:
See footnote on Page 114, Line 17, Column G.
'Schedule Page: 114 Line No.56 Column:
See footnote on Pa e 114, Line 17, Column G.
Schedule Pa e: 114 Line No.76 Column: d
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 04/25/2005 2004104
FOOTNOTE DATA
Amount charged to FERC Account 190.1, Accumulated Deferred Income Taxes.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 120 Line No.Column:
FERC
Amount 2004 Amount 2003 Account
44,855,410 47,772,747 404
901 583 4,427,976 404
5,479,353 5,479,353 406.
333,105 27,759 407.
674 863 844 942 407.
787,304 095,688 407.3 - 407.4
950,926 020,510 407.3 - 407.4
774 004 752,038 404
68,756,548 64,229,637
FERC
Amount 2004 Amount 2003 Account
178,421 368 241 182.3/216/242/253/283
11,069,299 11,245,891 151
17,290,644 15,907,514 151
637,454 012,948 254/411.6/411.7
12,975,669 182.
571,194 182.
33,529,000 254
438,351 253.4 / 253.41
179,924 18,494,059 182.
55,345,594 96,101,624 182.
29,325,548 731,554 228.
315 275 742 881 107
14,584 594 506,114 228 / 253
471,652 187,668
556,414 133,601,263
Amortization of Software Development
Amortization of Other Intangible Assets
Amortization of Electric Plant Acq. Adj. - Common
Amortization of Regulatory Assets - Debits
Amortization of Unrecovered Plant - Trojan
Amortization of Regulatory Liabilities - Credits
Amortization of Regulatory Assets - Credits
Other
ISchedule Page: 120 Line No.: 18 Column:
FAS 133 Derivative Adjustments
Coal Depreciation & Depletion included in Cost of Fuel
PMI Equity Earnings included in Cost of Fuel
(Gain)/Loss on Sale of Property
Establish 2003 UT & OR & ill Rate Orders
Establish Trail Mountain Mine Reg Asset per Reg Order
Establish Regulatory Liability BP A/SMUD
Deferred Credits - Deferred Compensation
OR, UT, WY & ill Reg Orders - Deferred Excess Net Power Costs
OR, UT, WY & ill Orders - Def Excess Net Power Costs Amort
Accumulated Provision for Pension & Benefits
Write-Off of Assets Under Construction
Accumulated Provision for Mining/EnvironlDecom
Other
ISchedule Page: 120 Column: Line No.
Other Investments/Special Funds
Temporary Facilities
FAS 115 M-M Securities Adjustments (Unrealized)
Minimum Pension/SERP Liability Adjustment (OCI)
Schedule Page: 120
Amount 2004
518,396
199
322 711
842 306
Amount 2003
379,218
112,272
29,779
- 785,576
022 743
FERC
Account
124/ 128
185
219
219
Line No.Column: b
Inter-Company Borrowing (Note Agreements)
Schedule Page: 120
FERC
Amount 2004 Account
883,910 233
Line No.Column:
Advances from Associated Companies
Inter-Company Borrowing (Note Agreements)
I FERC FORM NO.1 (ED. 12-87)Page 450.
FERC
Amount 2003 Accourn
362,888,000 223
259,000 233
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
362 629,000
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Oa, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 122(a)(b) Line No.
Represents balance at 01/01/2004
'Schedule Page: 122(a)(b Line No.
Re resents balance at 01/01/2004
Schedule Page: 122 a)(b) Line No.
Re resents balance at 09/30/2004
Schedule Page: 122 a) b) Line No.
Represents balance at 09/30/2004
Column:
Column: b
Column: b
Column:
IFERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 200 Line No.
Depreciation 5,422,694,287
Depletion 40,724,460
463,418 747
Column: c
I FERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 204 Line No.Column:
Line Account Description
Balance at
Begining
of Year
(c)
Balance at
End of
Year
(g)
Additions Retirements Transfers
No. (a)(b)(d)(e)(f)
39921 LAND OWNED IN FEE 634 916 634 916
39922 LAND RIGHTS 55,561,367 55,561,367
39930 STRUCTURES 45,001,967 611,268 (16,175)597,060
39941 SURFACE - PLANT EQUIPMENT 11,236,746 236,746
39942 SURFACE - DRAGLINE
39943 SURFACE - RAILROAD EQUIPMENT 664,816 664,816
39944 SURFACE - ELECTRIC POWER FACILITIES 566,476 566,476
39945 UNDERGROUND - COAL MINE EQUIPMENT 45,856,555 (132,829)52,450,412726,686
39946 LONGW ALL SHIELDS 678 600 678 600
39947 LONGW ALL EQUIPMENT 11 ,810 531 809,115)582 330580,914
39948 MAINLINE EXTENSION 11,028,902 640,772 (621,138)12,048,536
39949 SECTION EXTENSION 863,287 714,341851,054
39951 1,824 613 (18,430)(249,338)644,346VEHICLES87,501
39952 HEAVY CONSTRUCTION EQUIPMENT 068,345 485,117 (327,553)225 909
39960 MISCELLANEOUS GENERAL EQUIPMENT 534 784 158 211 665,091(27 904)
39961 730,726 70,456 785,412(15,770)COMPUTERS - MAINFRAME
39970 MINE DEVELOPMENT AND ROAD EXTENSTION 23,621,897 31,125,222503,325
18 399915 Coal Mine ARO
TOTAL PLANTUSED IN MINING ACTIVITIES (3,968,914)(249,338)272 181 580256,684,528 19,715,304
ISchedule Page: 204 Line No.88 Column:
See footnote line 88, column b.
ISchedule Page: 204 Line No.88 Column: d
See footnote line 88, column b.
ISchedule Page: 204 Line No.88 Column: f
See footnote line 88, column b.
'Schedule Page: 204 Line No.88 Column: g
ee footnote line 88, column b.
fSchedule Page: 204 Line No.93 Column:
PacifiCorp has sold the Naches and Naches Drop Hydroelectric Plants to the United States Bureau of Reclamation. Water Rights,
along with some buildings and equipment were turned over to the Bureau of Reclamation on March 10 2003. Access to the remainder
of the building and equipment was granted to the United States Bureau of Reclamation effective January 1,2004. The third
amendment to the water rights purchase agreement was executed November 1, 2004. Transfer of the land rights per this agreement
IFERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
occurred on March 31, 2005. A letter dated July 28, 2004 to the Federal Energy Regulatory Commission (the "FERC") for permission
to clear FERC account 102 was a roved b FERC on November 22, 2004.
Schedule Pa e: 204 Line No.93 Column:
PacifiCorp and six other minority owners sold their interest in the 1 MW Skookumchuck Hydroelectric project to a subsidiary of
Alberta Based TransAlta for $7.4 million. PacifiCorp s share was $3.5 million. The sale was completed on October 5,2004, with the
proceeds, net book value, and selling costs transferred to FERC account 102. Additional closing costs were booked in December 2004
and cleared to FERC account 102. A letter to the FERC for pennission to clear account 102 is pending.
IFERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 214 Line No.Column:
The North Horn Mountain Coal Properties are needed to access future coal portals and federal coal reserves when existing East
Mountain coal mines are mined out.
ISchedule Page: 214 Line No.Column:
To be converted to 138 kV, scheduled in service date is 2005.
'Schedule Page: 214 Line No.Column:
Vmous dates and plans.
'Schedule Page: 214 Line No.25 Column:
Various dates and plans.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 216.Line No.Column:
A $1 000,000 reporting threshold was approved for PacifiCorp effective with the 1993 reporting year by the Chief Accountant, Federal
Regulatory Commission in a letter to the company dated August 5, 1993, Docket No. AC93-181-000.
I FERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 219 Line No.Column: b
Account 151 Fuel Stock
Account 143.3 Joint Owner Receivable - Deprec. expense billed to Joint Owners
Account 182.3 Other Regulatory Assets
Vehicle Depreciation allocated to O&M based on usage activity
Account 503.1 Blundell Depletion
Account 421 Depreciation for Future Use
Total Other Accounts
11,273,241
183,156
318,585
10,640,856
1,211,674
720
25,630,232
Schedule Page: 219 Line No.16 Column: b
Other items including:
Recovery from third parties for asset relocations and damaged property,
Insurance recoveries,
Adjustments of reserve related to electric plant sold, and
Reclassifications from electric plant
Total
24,560,887
24,560,887
I FERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
Schedule Pa e: 232.Line No.Column: d
Account 282
Account 254
Schedule P e: 232.Line No.Column: d
Account 440
Account 442
Account 444
Schedule Page: 232.Line No.Column: d
Account 440
Account 442
Account 444
Schedule Page: 232.Line No.: 10 Column: d
Account 440
Account 442
Account 444
Schedule Page: 232.Line No.Column: d
Account 440
Account 442
Account 444
Schedule Page: 232.Line No.Column: d
Account 175
Account 244
Account 421
Account 426.
Schedule Pa e: 232.Line No.Column: d
Various Expense Accounts
Schedule Page: 232.Line No.: 30 Column: d
Account 219
Account 228.
IFERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Oat Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 234
Line 7:
Line No.Column: b
Bond Refinancing
Deferred Compensation
Bad Debt
Obsolete Parts
Cholla/GE Contract Administration
Supplemental Executive Retirement Plan (SERP)
Sales of Emission Allowances
Federal Income Tax Interest
Sick Leave, Vacation & PT
Injuries & Damages
Trojan Decommissioning
Other M-l Line 4 & 5 Differences
NW Power Act
Noncash Pension, Bonus & Severance
Utility Asset Writedowns
Property Tax Litigation Accrual
Bonus Liability
Glenrock 263A
Exchange Tulana Farms
Sec 174 R & E Expenditures
PMI Deferred Tax Adjustments
Centralia Mining Company
Monsanto Contract
Redding Contract
Glenrock Overburden Amort
Utah Rate Case Refund
CAIMT Asset Writeoff
University of WY Contract
Minimum Pension Liability Adj.
Minimum SERP Liability Adj.
FAS 143 ARO Adj.
Balance at Beginning
of Year
119,264
3,434,588
19,040,048
762,272
190 446
681 353
(123,489)
(256)
807,588
168,199
(3,637,136)
(38,718,377)
625,243
(42 944 050)
22,283,418
(16,939,732)
334 489
(3,183,815)
295,695
9,160,594
15,271,527
(4,525,891)
511,553
(3,447,242)
23,127,569
(110 621 )
(1,238)
838,344
300,943
558,242
Total 50,879,528
ISchedule Page: 234
Line 7:
Line No.Column:
BETC Credit Carryforward
Regulatory Liabilities
Employee Benefits
FAS 133 Derivatives
Other Deferred Assets
Balance at End of
Year
504 700
329,770,325
167,963,538
115,933,333
153,786,568
Total 767.958,464
ISchedule Page: 234
Line 17 - Other (Non-Utility):
Line No.Column: b
Malin Line
30 South Substation Site Writedown
Nonutility Asset Writedown
Centralia Mining Reclamation - NOB'
Yakima Hydro Licensing Fee
Trail Mountain Closing Costs
Balance at Beginning
of Year
551,411
245,409
142 666
726 577)
101 661)
202 271 )
Total 908,977
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 250 Line No.Column: c
Common stock has no par or stated value.
ISchedule Page: 250 Line No.Column:
This class of stock is not redeemable.
ISchedule Page: 250 Line No.Column:
Exce t as s ecifically noted, all referred stock series trade as unlisted securities.
Schedule Page: 250 Line No.13 Column:
This series of refeITed stock is not redeemable.
Schedule Page: 250 Line No.14 Column:
This series of prefeITed stock is not redeemable.
ISchedule Page: 250 Line No.29 Column:
Authorizations for the issuance of common stock by PacifiCorp to its immediate corporate parent, PacifiCorp Holdings, Inc.
(50,000,000 shares authorized; 35,148,515 available as of December 31, 2004) are as follows:
Oregon Public Utility Commission, Docket No. UF-4193, Order No. 02-769, dated October 30, 2002.
Washington Utilities and Transportation Commission, Docket No. UE-021259, dated October 23, 2002.
Idaho Public Utilities Commission, Docket No. PAC-02-, Order No. 29144, dated October 30, 2002.
IFERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
'Schedule Page: 253 Line No.Column: b
This represents a capital contribution made to Interwest Mining, a direct subsidiary ofPacifiCorp, in June 2004. It represents the cash
movement required by the Public Utility Holding Company Act (PUHCA) rule 45(c) arising from the tax benefits owed to Interwest
Mining from PacifiCorp as a result of the PacifiCorp Holdings Inc. (PHI) filing on a consolidated tax return basis. This same amount
was paid as a dividend back to PacifiCorp in June 2004 as reported on the Statement of Retained Earnings page 119 line no. 51.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 04/25/2005 2004104
FOOTNOTE DATA
Schedule Pa e: 256 Line No.17 Column:
On August 24, 2004, PacifiCorp issued $200.0 million of its 4.95% Series of First Mortgage Bonds due August 15,2014, and $200.
mi llion of its 5.90% Series of First Mortgage Bonds due August 15, 2034. Authorizations for the issuances were as follows:
Oregon Public Utility Commission, Docket No. UF-4167, Order No. 99-786, dated December 23, 1999 and Supplemental Order No.
01-965, dated November 13,2001.
Washington Utilities and Transportation Commission, Docket No. UE-991745, dated December 8 1999.
Idaho Public Utilities Commission, Case No. PAC-03-, Order No. 29238, dated Ma 14,2003.
Schedule Pa e: 256 Line No.25 Column:
See footnote line 17 column a.
Schedule Page: 256.Line No.27 Column:
On December 13,2004, PacifiCorp redeemed the 8.625% Series F Medium-Term Notes due December 13,2024 and transferred
$100,807 from account 181 (Unamortized Debt Expense) and $332,788 from account 226 (Unamortized Discount on Long-Term
Debt) to account 189 (Unamortized Loss on Reacquired Debt).
ISchedule Page: 256.Line No.20 Column:
Pollution Control Obligations Secured by Pledged First Mortgage Bonds
Issue
Poll Ctrl Revenue Refunding Bonds, Series 1994
Poll Ctrl Revenue Refunding Bonds, Series 1994
Poll Ctrl Revenue Refunding Bonds, Series 1994
Poll Ctrl Revenue Refunding Bonds, Series 1994
Poll Ctrl Revenue Refunding Bonds, Series 1994
Poll Ctrl Revenue Refunding Bonds, Series 1994
Poll Ctrl Revenue Refunding Bonds, Series 1988
Poll Ctrl Revenue Refunding Bonds, Series 1991
Poll Ctrl Revenue Bonds, Series 1984
Poll Ctrl Revenue Bonds, Series 1986
Environ Improvrnnt Rev Bonds, Series 1995
Environ Improvrnnt Rev Bonds, Series 1995
625 % Series Due Nov. 2021
650% Series Due Nov. 2023
625% Series Due Nov. 2023
Amount Pledgee
40,655,000 Moffat County, CO
21,260,000 Sweetwater County, WY
190,000 Converse County, WY
121,940,000 Emery County, UT
365,000 Carbon County,
15,060,000 Lincoln County, WY
17,000,000 Converse County, WY
45,000,000 Lincoln County, WY
15,000,000 Sweetwater County, WY
500,000 City of Forsyth, MT
300,000 Converse County, WY
22,000,000 Lincoln County, WY
300,000 Lincoln County, WY
46,500,000 Emery County, UT
16,400,000 Emery County, UT
'Schedule Page: 256.4 Line No.17 Column:
As of December 31, 2004, there were 525,000 shares outstanding ($100 stated value per share) on the $7.48 series subject to the
following mandatory redemption requirements: 37,500 shares are subject to mandatory redemption on each June 15 from 2005
through 2006, with all shares outstanding on June 15,2007 subject to mandatory redemption on that date.
ISchedule Page: 256.Line No.22 Column:
Authorization for the issuance of pollution control revenue bonds ($125,000,000 authorized; $79 225,000 available as of
December 31, 2004) is as follows:
Oregon Public Utility Commission, Docket No. UF-4128, Order No. 95-518, dated May 25, 1995.
Washington Utilities and Transportation Commission, Docket No. UE-950490, dated May 24, 1995.
Idaho Public Utilities Commission, Docket No. PAC-95-, Order No. 26039, dated June 13, 1995.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Oa, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 261 Line No.
Particulars (Details)
Column:
Amount
Other Line 8:
Contributions in Aid of Construction
Highway relocation
Regulatory assets - FAS 133
Oregon UE 134 Power Cost
Weather Derivatives
SMUD Revenue Imputation-UT reg liab
Unearned Joint Use Pole Contact Revenue
27,641,048
434 690
229,079,286
885,080
937,726
37,476,103
116,715
Total 316,570,649
'Schedule Page: 261 Line No.
Particulars (Details)
Column:
Amount
Other Line 13:
Federal Income Tax
Book Cost Depletion - Addback
Merger Transaction Costs
Trapper Mine Dividend Deduction
Mandatory Redeemable Preferred Stock - FAS 150
Meals & Entertainment
Penalties
Lobbying expenses
SP Management fee
Meals & Entertainment - Bridger Coal
Book Depreciation
Tax vs Book Depreciation - PMl
30% capitalized labor costs for Powertax input
Avoided Costs
Acquisition Adjustment Amort
Trojan Decomissioning Costs - Regulatory
Weatherization
Min. Pension Liability Adjustment
FAS 87/88 Deferred Pension
Severance Accrual - Cash Basis
May 2000 Transition Plan Costs-
May 2000 Transition Plan Costs-
May 2000 Transition Plan Costs-
May 2000 Transition Plan Costs-
May 2000 Transition Plan Costs-WYE
May 2000 Transition Plan Costs-WYW
FAS 87/88 Pension Writeoff - UT rate order
Y2K Expense-
BSIP/SAP-
Glenrock Excluding Reclamation-
97 Software WriteDown-
99 Software WriteDown-
Transition Team Costs-
DefReg Asset-IDU DefNet Power Costs
DefReg Asset-OR DefNet Power Costs
DefReg Asset-UT DefNet Power Costs
Oregon UE 137 Power Cost
Environmental Clean-up Accrual
Cholla PIt Transact Costs-APS Amort
Trail Mountain Mine Closure
Trail Mountain Unrecovered Inventory
IDAI Costs - direct access
W A Disallowed Colstrip #3- Write-off
SB 1149-Related Regulatory Assets
122,739,939
411,123
901
290,038
980,926
1,765,650
145,463
1,153,038
768,333
29,708
365,964,889
5,466,368
798,604
736 066
659,396
819 682
15,576,722
546,879
88,919,305
15,774,036
603,735
192,729
11,159 763
257 144
375,162
774 170
159,014
268,659
805,361
302,400
514 363
367 023
485,905
291 964
33,598,499
32,253,273
869,962
805,441
572,994
047,101
304 104
111 035
188
285 383
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 04/25/2005 2004104
FOOTNOTE DATA
SERP Accrual - Cash Basis
Coal Pile Inventory Adjustment
Deferred Financing Costs
Energy trading derivatives - current
Centralia Gain Gi ve Back - OR
TGS Buyout
Lakeview Buyout
Buffalo Settlement
Joseph Settlement
TriState Firm Wheeling
Mead Phoenix Availability &Trans Charge
Clark Finn Transmission
Firth Cogen Settlement
Option Energy Purchases
Henniston Swap
Prepaid Taxes - OR PUC
Prepaid Taxes - W A UTC
Prepaid Taxes - ill PUC
Prepaid Taxes - WY PSC
Prepaid Membership Fees - EEl, WSCC
Pollution Control Facility (Book v. Tax Amort)
Wasach workers comp reserve
Bridger Coal Company Section 471 Adjustment - PMI
Non-ARO Liabilily - Reg Liability
Reg liability BPA balancing accounts
Deferred Compensation Accrual - Cash Basis
Vacation Accrual- PMI
SERP
Reg Assets/Reg Liabilities - total
Min. Pension Liability Adjustment
Steam Rights Bunden Geothermal
Bad Debts Allowance - Cash Basis
Injuries and Damages Accrual - Cash Basis
M&S Inventory Write-Off
Vacation Accrual - Cash Basis (2.5 mos)
NW Power Act-
Trail Mountain Accrued Liabilities
Purchase Card Trans Povision
Misc. Current and Accrued Liability
Centralia Sale
Reverse Accrued Final Reclamation
R & E - Sec.l74 Deduction
Minimum SERP Liab - OCI
Legal Reserve
Oregon BETC Credits
Sec. 263A Inventory Change - PMI
14,252 645
358,574
327,140
118,586
710
43,280
45,176
137,381
059,480
377,760
934,669
397 893
740 000
539,573
322,510
33,383
14,439
170,512
073,445
90,134
602,577
304 520
146,738
688 188
214 022
42,076
919,000
40,722,859
304,000
211 ,049
795,144
998,026
83,269
422 693
476 724
176 164
359,704
16,404,691
17,620
22,816,589
386,277
785,577
000 000
704 131
646
Total 968,714 008
jSchedule Page: 261 Line No.
Particulars (Details)
Column:
Amount
Other Line 26:
Allowance for Funds Used During Construction
Equity Earnings in Subsidiaries
Tax Percentage Depletion - Deduction
Tax Exempt Interest (No AMT)
Utah Deferred Compensation ICOLI
PPL Pre - 1943 Preferred Stock Dividend - Deduction
SPI 404(k) Contribution
Bridger Coal Tax Exempt Interest Income
Bridger Coal Company Depletion - PMI
Tax Depreciation
Depreciation (Tax Depreciation M -1 )
I FERC FORM NO.1 (ED. 12-87
634 086
1.814 271
1,472,904
757
444,682
336,365
392,876
440,005
479,641
526 638,601
626,731
Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubm Ission 04/25/2005 2004104
FOOTNOTE DATA
Capitalized Depreciation
Gain / (Loss) on Prop. Disposition
ADR Repair Allowance 3115
Coal Mine Development
Coal Mine Extension
Removal Cost (net of salvage)
Coal Mine Development- 30% Amortization
Cholla SHL (Tax Int. - Tax Rent)
Malin SHL (Tax Int. - Tax Rent + Book Dep)
Pension / Retirement Accrual - Cash Basis
Noell Kempf CAP - UT
P&M Strike Amortization - UT
98 Early Retirement-OR rate order
Post Merger Loss-Reacq Debt - Addback
CA Write-off Amort
MT Write-off Amort
Deferred Intervener Funding Grants
Reg Assets BPA balancing accounts
Contra-reg assets - transition plan
Min. Pension Liability Adjustment
W A state Transition Costs
Deferred Projects
Prepaid Taxes - UT PUC
Prepaid Taxes - CA Property Taxes
Prepaid Taxes - OR Property Taxes
WY Joint Water Board Reserve - Deduction
Trail Mountain Closing Costs
Misc. Timing Difference - PMI
Bridger Coal Company Reclamation Trust Earnings - PMI
Bridger Coal Company Extraction Taxes Payable - PMI
Oregon Share of Henniston
Oregon Gain on Sale
Property Insurance(same as Injuries & Damages)
ARO Reg Liabilities
Regulatory Asset 186.
FAS 87/88 DefelTed Pension - Reg Asset
FAS 106 Accruals - Cash Basis
Bonus Liability - Electric - Cash Basis (2.5 mos)
Bonus Accrual - PMI
OCl
SERP Accrual - Non Reg Asset
U of WY Contract Amort - Prepaid
Def Reg Asset-Transmission Srvc Deposit
Coal M&S Inventory Write-Off-Centralia
Def Reg Asset-Foote Creek Contract
NW Power Act-
Redding Contract - Prepaid
Distribution O&M Amort of Writeoff
Weather Derivatives
Amort of Debt Disc & Exp
Montana Sale Accrual
Defer MagCorp Revenues
DefelTed Regulatory Asset
DefelTed Regulatory Expense
Bogus Creek Settlement
Idaho Customer Balancing Account
Special Assessment - DOE
Extraction Tax Accruals - Cash Basis (8.5 mos)
Interest Accual on FIT - Cash Basis
Centralia Give Back-W A
Centralia Give Back-
Merger Credits - OR
Merger Credits - WA
Amort of Projects-Klamath Engineering
State Tax Deduction
I FERC FORM NO.1 (ED. 12-87)
995,381
50,138 370
103,286
551 ,260
1,431 000
766,603
753.672
056,327
619,788
21,062,283
46,938
723,670
788,551
137,292
352,865
327,405
155.085
208,197
22,452,786
882,000
152,730
896,349
271
935
277 701
858
261.354
808
016,237
54,786
060,848
969 068
058 175
451,974
032,864
88,919 309
760,197
015,874
838
10,673,456
15,728,914
346
161 006
301,787
137 640
559,782
155,571
644,306
383,818
622
399,550
036,174
70,218,480
000
118,000
099,549
10,926
803,590
538,139
879,807
196,517
099,548
3,454 813
6,423
802,287
Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
Total 071 306,904
I FERC FORM NO.1 (ED. 12-87)Page 450.4
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
Schedule Pa e: 262 Line No.Column:
Reclassified to deferred taxes.
Schedule Page: 262 Line No.Column: I
Taxes a plicable to Other Income & Deductions - 408.2 & 409.
Schedule Page: 262 Line No.Column:
Prior eriod items reclassified to 232 - Accounts a able
Schedule Pa e: 262 Line No.Column: I
Various 0 erations and Maintenance Accounts
Schedule Pa e: 262 Line No.Column: I
Fuel Invento - 15 1
Schedule Pa e: 262 Line No.Column:
Prior period items reclassified to 232 - Accounts ayable
Schedule Pa e: 262 Line No.Column: I
Fuel Invento - 151
Schedule Pa e: 262 Line No.11 Column:
Reclassified from State (General) to s ecific states.
Schedule Page: 262 Line No.17 Column:
Reclassified from State (General) to s ecific states.
Schedule Pa e: 262 Line No.17 Column: I
Taxes applicable to Other Income & Deductions - 408.2 & 409.
Schedule Page: 262 Line No.18 Column: I
Clearin Account - 184
Schedule Pa e: 262 Line No.23 Column:
Reclassi balance to re aid ro erty tax.
Schedule Page: 262 Line No.23 Column: I
Taxes applicable to Other Income & Deductions - 408.2 & 409.2
Distribution Rent Expense, Rents - 589
23,796
848
27,664
I FERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
Taxes ap licable to Other Income & Deductions - 408.2 & 409.
Schedule Page: 262.Line No.Column: I
Various Operations and Maintenance Accounts
'Schedule Page: 262.Line No.Column: f
Reclassified to Pre aid Fees, Pre a ments - 165
Schedule Pa e: 262.Line No.Column: I
Various 0 erations and Maintenance Accounts
Schedule Pa e: 262.Line No.Column: I
Clearin Account - 184
Schedule Pa e: 262.Line No.: 10 Column: f
Reclassified from State (General) to s ecific states.
Schedule Page: 262.Line No.: 10 Column: I
Taxes a licable to Other Income & Deductions - 408.2 & 409.
Schedule Page: 262.Line No.17 Column: I
Various Operations and Maintenance Accounts
'Schedule Page: 262.Line No.28 Column: I
Taxes applicable to Other Income & Deductions - 408.2 & 409.
Distribution Rent Expense, Rents - 589
35,452
45,706
81,158
ISchedule Page: 262.Line No.29 Column: I
Various Operations and Maintenance Accounts
'Schedule Page: 262.Line No.: 30 Column: I
Various 0 erations and Maintenance Accounts
Schedule Page: 262.Line No.31 Column: f
Reclassified from State (General) to s ecific states.
Schedule Page: 262.Line No.31 Column: I
Taxes applicable to Other Income & Deductions - 408.2 & 409.
'Schedule Page: 262.Line No.32 Column: f
Reclassified from State (General) to specific states.
ISchedule Page: 262.Line No.32 Column: I
Taxes applicable to Other Income & Deductions - 408.2 & 409.
ISchedule Page: 262.Line No.34 Column: I
Various Operations and Maintenance Accounts
'Schedule Page: 262.Line No.35 Column: I
Various Operations and Maintenance Accounts
jSchedule Page: 262.Line No.38 Column: f
Reclassified to Pre aid Fees, Pre a ments - 165
Schedule Pa e: 262.Line No.38 Column: I
Various 0 erations and Maintenance Accounts
Schedule Pa e: 262.Line No.39 Column: f
Reclassified Multnomah County Tax to Taxes Payable, Tax Collections Payable - 241
ISchedule Page: 262.Line No.Column: I
Various 0 erations and Maintenance Accounts
Schedule Page: 262.Line No.Column: I
Taxes a licable to Other Income & Deductions - 408.2 & 409.
Schedule Pa e: 262.Line No.: 10 Column: f
Reclassified from State (General) to s ecific states.
Schedule Page: 262.Line No.: 10 Column: I
Taxes a licable to Other Income & Deductions - 408.2 & 409.
Schedule Page: 262.Line No.11 Column: I
Various 0 erations and Maintenance Accounts
Schedule Page: 262.Line No.12 Column:
I FERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
Various 0 erations and Maintenance Accounts
Schedule Page: 262.Line No.14 Column: I
Clearing Account - 184
ISchedule Page: 262.Line No.16 Column:
Reclassify Interwest Mining Sales & Use Tax from Miscellaneous Taxes.
ISchedule Page: 262.Line No.17 Column:
Reclassified to Pre aid Fees, Pre a ents - 165
Schedule Pa e: 262.Line No.17 Column: I
Various 0 erations and Maintenance Accounts
Schedule Pa e: 262.Line No.23 Column: I
Taxes applicable to Other Income & Deductions - 408.2 & 409.
Distribution Rent Expense, Rents - 589
78,000
829
80,829
ISchedule Page: 262.Line No.24 Column: I
Various Operations and Maintenance Accounts
ISchedule Page: 262.Line No.27 Column: I
Clearin Account - 184
Schedule Pa e: 262.Line No.29 Column:
Reclassified to Miscellaneous Current and Accrued Liabilities - 242
ISchedule Page: 262.Line No.29 Column: I
Various 0 erations and Maintenance Accounts
Schedule Pa e: 262.Line No.35 Column: I
Various Operations and Maintenance Accounts
ISchedule Page: 262.Line No.Column: I
Taxes applicable to Other Income & Deductions - 408.2 & 409.
Distribution Rent Expense, Rents - 589
240
15.676
15,916
jSchedule Page: 262.Line No.Column:
Reclassify Glenrock Property Tax from Miscellaneous Taxes.
ISchedule Page: 262.Line No.Column: I
Fuel Inventor - 151
Schedule Pa e: 262.Line No.Column: I
Various 0 erations and Maintenance Accounts
Schedule Pa e: 262.Line No.Column: I
Various 0 erations and Maintenance Accounts
Schedule Pa e: 262.Line No.Column:
Reclassi Black Lun liabilit to Glenrock Black Lung Tax from Glenrock Production Tax.
Schedule Pa e: 262.Line No.Column: I
Glenrock Mine Reclamation, Asset Retirement Obli ations - 230
Schedule Pa e: 262.Line No.Column:
Reclassify Black Lung liability to Glenrock Black Lung Tax from Glenrock Production Tax.
'Schedule Page: 262.Line No.Column: I
Glenrock Mine Reclamation, Asset Retirement Obli ations - 230
Schedule Pa e: 262.Line No.Column:
Reclassify Glenrock Sales and Use Tax from Miscellaneous Taxes.
ISchedule Page: 262.Line No.Column: I
Glenrock Mine Reclamation, Asset Retirement Obli ations - 230
Schedule Pa e: 262.Line No.Column: I
Clearin Account - 184
Schedule Pa e: 262.Line No.21 Column:
Reclassified to Accounts Payable - 232
Reclassified to Accounts Receivalbe from Associated Companies - 146
943,182
21,163
I FERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 262.
Reclassify to:
922,019
Line No.Column:
Glenrock Sales and Use Tax
Glenrock Property Tax
Interwest Mining Use Tax
236
66,318
724
71,309
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
Schedule Pa e: 269 Line No.Column: c
Account 456.
Account 447
Schedule Pa e: 269 Line No.Column: c
Account 456
Account 142
Schedule Pa e: 269. 1 Line No.Column: c
Account 232
Account 426
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 274 Line No.Column:
In 2004, PacifiCorp preformed a study on the accumulated deferred income tax balances. As a result of this study, PacifiCorp adopted
a uniform accounting methodology for accwnulated deferred income taxes for both FERC and SEC reporting purposes. For FERC
reporting purposes, some reclassifications were made between accwnulated deferred income tax assets account 190 and accumulated
deferred income tax liability accounts 282 and 283 (net/gross presentation). The reclassification had a balance sheet only effect. If the
results of the deferred tax study had been applied to calendar year 2003 the ending accumulated deferred income tax liabilities in
account 282 for CY 2003 would have been approximately $1,884,198,440.
IFERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 276 Line No.Column:
Balance at Amounts Amounts Amounts Acct.Amount Acct.Amount Balance at End
Begmning of Debited to Credited to Debited to Cr.Dr.of Year
Year Account 410.Account 411.Account
410.
Other Line 8:
UPUPPL Merger Amort 137,447)190 137,447
Loss on Reacquired Debt 318,805 283 318,805
Purchase Pwr Agree. Settle.(3,016,390)190 016 390
Other M-l Differences (3,938,051)190 938 051
Hermiston Breakage Fee 612,080 612 080
Special Assessment 138,909 283 138,909
FAS 106 (13,571,217)190 13,571,217
Regulatory Asset 781,164)190 781,164
Coalpile Inventory Adj.665,963 283 665,963
Weath./Cust. Sec.16,905 400 283 16,905,400
Prepaid Taxes 19,479,338 283 19,479,338
Trust Income & Exp.(922 772)190 922,772
Hazardous Waste (10,446 102)190 446 102
Extraction Tax (102,309)190 102 309
83 -88 IRS Settlement (5,542,936)190 542 936
Amort. Poll. Cont. Liab.306,885 283 306 885
Software Write-off (41,328,249)190 328,249
PMI Defen-ed Tax Adj.909,344 283 909,344
GCC Defen-ed Tax Adj.(1,737,968)190 1,737,968
FAS133 Derivatives 201 483)190 201,483
Aowthrough Part. Inc.058 884 283 058,884
Regulatory Assets 177,521,002 15,607,829 161 913,173
FAS 133 Derivatives 105,452,383 105,452,383
Other Defen-ed Liab.37,770,931 609,100,151 509,824 283 (54 395,608)190 609,366 905 943,116
Total (37 330,480)320 744 316 624 707,980 509,824 701,092 993 360,308,672
ISchedule Page: 276 Line No.Column: k
In 2004, PacifiCorp preformed a study on the accumulated deferred income tax balances. As a result of this study, PacifiCorp adopted
a uniform accounting methodology for accumulated deferred income taxes for both FERC and SEC reporting purposes. For FERC
reporting purposes, some reclassifications were made between accumulated deferred income tax assets account 190 and accumulated
deferred income tax liability accounts 282 and 283 (net/gross presentation). The reclassification had a balance sheet only effect. If the
results of the deferred tax study had been applied to calendar year 2003 the ending accumulated deferred income tax liabilities in
account 283 for CY 2003 would have been approximately $493,772,249.
I FERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Oa, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
Schedule Pa e: 278 Line No.Column: c
Account 182.
Account 282
Schedule Page: 278 Line No.Column: c
Account 431
Account 456
Schedule Page: 278 Line No.Column: c
Account 440
Account 444
Account 446
Schedule Page: 278 Line No.Column: c
Account 431
Account 456
Schedule Pa e: 278 Line No.Column: c
Account 440
Account 442
Schedule Page: 278 Line No.Column: c
Account 440
Account 442
Schedule Pa e: 278 Line No.: 10 Column: c
Account 440
Account 442
Schedule Page: 278 Line No.Column: c
Account 440
Account 442
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 300 Line No.11 Column: b
In July 2003, the Emerging Issues Task Force ("EITF') issued EITF No. 03-11. Effective January 1, 2004, PacifiCorp adopted EITF
No. 03-11, which provides guidance on whether to report realized gains or losses on physically settled derivative contracts not held for
trading purposes on a gross or net basis and requires realized gains or losses on derivative contracts that do not settle physically to be
reported on a net basis. The adoption ofEITF No. 03-11 resulted in PacifiCorp s netting certain contracts that were previously
recorded on a gross basis, which reduced Sales for Resale and Purchased Power. Since PacifiCorp has a fiscal year end of March 31,
the implementation ofEITF 03-11 resulted in a reclassification of $397.7 million at March 31,2004 for the fiscal year then ended (first
quarter of the calendar year). Consequently, since FERC reporting is based on a calendar year, the financial infonnation reported in
the following accounts contains the impact of the adjustment for the 12 month period ending March 31,2004 as opposed to just the 3
months impact. The following table summarizes the effect of adopting EITF 03-11 on each quarter of the fiscal year ended March 31,
2004, which was all recorded in the first quarter of the calendar year (fourth quarter of the fiscal year). Adoption of EITF No. 03-
had no impact on PacifiCorp' s Net income.
Sales for Resale
Purchased Power
Other Electric Revenues
QI-FY 04 Q2-, 04 Q3-FY 04
(O2-CY 03) (O3-CY 03) (O4-CY 03)
$113,426,335 $ 82 874,255 $108,970,755
(110,706,073) (104,699,500) (90,471,134)
(2,720,262) 21,825,245 (18,499,621)
Q4- FY
CY 04
$98,740,774
(91,782,690)
(6,958,084)
FY 2004 Total
$404,012,119
(397,659,397)
(6,352,722)
Schedule Page: 300 Line No.Column: b
Page 300 Page 304 Variance
Twelve Months Twelve Months Twelve Months
Ending Ending Ending
December 31.December 31 December 31
2004 2004 2004
905,283 161 905,283,161
812 631,284 812,631,284
748 767,664 748,767,664 (a)
16,037,366 16,037,366
19,703,361 19,703.361
139 139
502,422 975 502,422.975
327,969,719 327 969 719 (b)
830.392,694 502,422,975 327 969 719
Sales of Electricity
Residential Sales - Account 440
Commercial and Industrial Sales - Account 442
Small (Commercial)
Large (Industrial)
Public Street and Highway Lighting - Account 444
Other Sales to Public Authorities - Account 445
Sales to Railroads and Railways - Account 446
Interdepartmental Sales - Account 448
Total Sales to Ultimate Consumers
Sales for Resale - Account 447
Total Sales of Electricity
(less) Provision for Rate Refunds - Account 449.
Total Revenues Net of Provisions for Refunds 830,392,694 502,422,975
323,072 323,072
691 582 691 582
170,132 170.132
16,712,132 14,838,870
130,295,327 123,695,302
$ 2,989,584,939 $ 2,653,141 933
327,969 719
Other Operating Revenues
Forfeited Discounts - Account 450
Miscellaneous Service Revenues - Account 451
Sales of Water and Water Power - Account 453
Rent from Electric Property - Account 454
Interdepartmental Rents - Account 455
Other Electric Revenues - Account 456
873,262 (c)
600 025 (d)
Total Operating Revenues $ 336,443,006
IFERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmisslon 04/25/2005 2004104
FOOTNOTE DATA
(a) The large industrial line on page 300 includes account 442.2lndustrial Sales of $697 061,038 and account 442.3 Irrigation Sales of $51 ,706,626.
(b) Sales for Resale are not included on page 304 Revenue by Rate Schedule.
(c) The following schedule is a reconciliation between page 300 and 304 Rent from Electric Property. The items listed below do not have rate schedules.
510,436
362 826
873,262
540000 Office Rent
543000 Other RentlLeases
(d) The following schedule is a reconciliation between page 300 and 304 Other Electric Revenues. The items listed below do not have rate schedules.
361000 Steam Sales
385421 Interest Income - DSM Carrying Charge
498803 T-PPM Long Term Wheeling
283,007
773,633
543,385
600,025
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 310 Line No.Column: b
Settlement Adjustment
ISchedule Page: 310 Line No.Column: j
Settlement Adjustment
jSchedule Page: 310 Line No.12 Column: j
Accrual Adjustment
'Schedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
'Schedule Page: 310.Line No.Column: j
Liquidated Damages
'Schedule Page: 310.Line No.Column: b
Second , Economy and/or non-firm sales, includin some hourI firm transactions.
Schedule Page: 310.Line No.Column: j
Operating Reserves
'Schedule Page: 310.Line No.Column: j
Reserve Share
'Schedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
ISchedule Page: 310.Line No.Column: j
Operating Reserves
'Schedule Page: 310.Line No.11 Column: b
Settlement Ad' ustment
Schedule Pa e: 310.Line No.11 Column:
Settlement Adjustment
ISchedule Page: 310.Line No.12 Column: b
Basin Electric Power Company - FERC - T -11 - Contract termination date: 12 months notification.
'Schedule Page: 310.Line No.12 Column: j
Transmission Losses
'Schedule Page: 310.Line No.13 Column: b
Secondary, Economy and/or non-fITm sales, including some hourly firm transactions.
'Schedule Page: 310.Line No.Column: b
Black Hills Power & Light Company - FERC 236 - Contract termination date: December 31,2023.
'Schedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-fmn sales, including some hourly firm transactions.
'Schedule Page: 310.Line No.Column: b
Blandin City - FERC T-12 - Contract Termination date: March 1 2007.
Schedule Page: 310.Line No.Column: b
Bonneville Power Administration - FERC 543 - Contract termination date: Se tember 30, 2006.
Schedule Page: 310.Line No.Column: b
Bonneville Power Administration - FERC T -12 - Contract termination date: April 22, 2024.
'Schedule Page: 310.Line No.Column: j
Transmission Losses
jSchedule Page: 310.Line No.Column: j
Reserve Share
'Schedule Page: 310.Line No.10 Column: b
Settlement Ad' ustment
Schedule Pa e: 310.Line No.: 10 Column:
Settlement Ad' ustment
Schedule Pa e: 310.Line No.12 Column: b
Settlement Adjustment
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
'Schedule Page: 310.Line No.12 Column: j
Settlement Ad. ustment
Schedule Pa e: 310.Line No.Column:
Settlement Ad' ustment
Schedule Pa e: 310.Line No.Column:
Settlement Ad' ustment
Schedule Pa e: 310.Line No.Column:
Secondary, Econom and/or non-firm sales, includin some hourly firm transactions.
Schedule Page: 310.Line No.Column:
Transmission Losses
'Schedule Page: 310.Line No.Column:
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
ISchedule Page: 310.Line No.Column: j
Pond Sale
jSchedule Page: 310.Line No.Column:
Settlement Adjustment
ISchedule Page: 310.Line No.Column: j
Settlement Ad. ustment
Schedule Pa e: 310.Line No.Column:
Clark County PUD #1 - FERC T-12 - Contract Termination date: December 12,2007.
'Schedule Page: 310.Line No.10 Column:
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
ISchedule Page: 310.Line No.12 Column:
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
ISchedule Page: 310.Line No.13 Column: j
Transmission Losses
ISchedule Page: 310.Line No.14 Column: j
Liquidated Damages
'Schedule Page: 310.4 Line No.Column:
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
ISchedule Page: 310.Line No.Column: j
Transmission Losses
'Schedule Page: 310.4 Line No.Column:
Cowlitz County Public Utility District No.1 - FERC 234 - Contract Termination date: December 31, 2005.
'Schedule Page: 310.4 Line No.Column:
Secondary, Econom and/or non-fmn sales, includin some hourI firm transactions.
Schedule Pa e: 310.4 Line No.Column: j
Transmission Losses
'Schedule Page: 310.Line No.Column:
Settlement Adjustment
ISchedule Page: 310.4 Line No.Column: j
Settlement Ad. ustment
Schedule Pa e: 310.4 Line No.Column:
Secondary, Economy and/or non-firm sales, including some hourI firm transactions.
Schedule Pa e: 310.Line No.13 Column:
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
ISchedule Page: 310.Line No.Column:
Secondar , Econom and/or non-firm sales, including some hourly firm transactions.
Schedule Pa e: 310.Line No.Column: j
Transmission Losses
ISchedule Page: 310.Line No.Column:
I FERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 04/25/2005 2004104
FOOTNOTE DATA
Flathead Electric Coo erative, Inc. - FERC T-12 - Contract Termination date: September 30,2006.
Schedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
ISchedule Page: 310.Line No.Column: j
Operating Reserves
ISchedule Page: 310.Line No.Column: j
Pond Sale
jSchedule Page: 310.Line No.10 Column: b
Hurricane, City of - FERC T -12 - Contract Termination date: August 31.2007.
'Schedule Page: 310.Line No.11 Column: b
Settlement Adjustment
ISchedule Page: 310.Line No.11 Column: j
Settlement Ad' ustment
Schedule Pa e: 310.Line No.13 Column: b
Idaho Power Company - FERC - T -11 - Contract termination date: May 31, 2006.
'Schedule Page: 310.Line No.13 Column: j
Transmission Losses
'Schedule Page: 310.Line No.14 Column: b
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
ISchedule Page: 310.Line No.14 Column: j
Operating Reserves
'Schedule Page: 310.Line No.Column: j
Transmission Losses
'Schedule Page: 310.Line No.Column: j
Reserve Share
jSchedule Page: 310.Line No.Column: j
Transmission Losses
'Schedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
'Schedule Page: 310.Line No.11 Column: j
Transmission Losses
'Schedule Page: 310.Line No.12 Column: j
Liquidated Dama es
Schedule Page: 310.Line No.13 Column: b
Secondary, Econom and/or non-firm sales, includin some hourI firm transactions.
Schedule Page: 310.Line No.Column: j
Reserve Share
ISchedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
'Schedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
'Schedule Page: 310.Line No.Column: j
Operating Reserves
ISchedule Page: 310.Line No.Column: j
Transmission Losses
ISchedule Page: 310.Line No.10 Column:
PPM Ener is an affiliate of the res ondent.
Schedule Pa e: 310.Line No.10 Column: b
Settlement Ad' ustment
Schedule Pa e: 310.Line No.10 Column:
I FERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
Settlement Ad' ustment
Schedule Pa e: 310.Line No.11 Column:
PPM Ener is an affiliate of the res ondent.
Schedule Pa e: 310.Line No.11 Column: b
PPM Energy - FERC - T-ll - Contract tennination date: 12 months notification.
ISchedule Page: 310.Line No.11 Column: j
Transmission Losses
ISchedule Page: 310.Line No.12 Column:
PPM Ener is an affiliate of the res ondent.
Schedule Pa e: 310.Line No.12 Column:
Transmission Losses
ISchedule Page: 310.Line No.Column: b
Secondar , Econom and/or non-finn sales, includin some hourly firm transactions.
Schedule Pa e: 310.Line No.Column:
erating Reserves
Schedule Pa e: 310.Line No.Column: j
Reserve Share
ISchedule Page: 310.Line No.Column: b
Settlement Ad' ustment
Schedule Page: 310.Line No.Column: j
Settlement Ad'ustment
Schedule Pa e: 310.Line No.Column: b
PowerEX - FERC - T -11 - Contract termination date: October 31, 2004.
ISchedule Page: 310.Line No.Column: j
Transmission Losses
'Schedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-fmn sales, including some hourly finn transactions.
'Schedule Page: 310.Line No.Column: j
Transmission Losses
ISchedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-finn sales, including some hourly finn transactions.
'Schedule Page: 310.Line No.Column: b
Settlement Adjustment
'Schedule Page: 310.Line No.Column: j
Settlement Ad' ustment
Schedule Pa e: 310.Line No.Column: b
Public Service Company of Colorado - FERC 320 - Contract tennination date: October 31, 2022.
'Schedule Page: 310.Line No.10 Column: b
Secondary, Economy and/or non-finn sales, including some hourly finn transactions.
ISchedule Page: 310.Line No.10 Column: j
Transmission Losses
ISchedule Page: 310.Line No.11 Column: b
Secondary, Economy and/or non-fmn sales, including some hourly finn transactions.
ISchedule Page: 310.Line No.13 Column: b
Secondary, Economy and/or non-firm sales, including some hourly finn transactions.
'Schedule Page: 310.Line No.13 Column: j
erating Reserves
Schedule Page: 310.Line No.14 Column:
Liquidated Damages
ISchedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-finn sales, including some hourly firm transactions.
IFERC FORM NO.1 (ED. 12-87) Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
'Schedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
ISchedule Page: 310.Line No.Column: j
Operating Reserves
ISchedule Page: 310.Line No.Column: j
Reserve Share
Pond Sale
ISchedule Page: 310.Line No.Column: b
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
\Schedule Page: 310.Line No.Column: j
Transmission Losses
ISchedule Page: 310.Line No.Column: b
Settlement Ad"ustment
Schedule Pa e: 310.Line No.Column: j
Settlement Ad" ustment
Schedule Pa e: 310.Line No.10 Column: b
Sacramento Municipal Utility District - FERC 250 - Contract termination date: December 31 , 2014.
ISchedule Page: 310.Line No.12 Column: b
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
ISchedule Page: 310.10 Line No.Column: j
Reserve Share
'Schedule Page: 310.10 Line No.Column: b
Secondary, Economy and/or non-firm sales, includin some houri firm transactions.
Schedule Page: 310.10 Line No.Column:
Transmission Losses
ISchedule Page: 310.10 Line No.Column: b
Secondary, Econom and/or non-firm sales, includin some hourly firm transactions.
Schedule Page: 310.10 Line No.Column: b
Settlement Adjustment
ISchedule Page: 310.10 Line No.Column: j
Settlement Ad' ustment
Schedule Pa e: 310.10 Line No.Column: b
Sierra Pacific Power Company - FERC 258 - Contract termination date: February 28,2009.
ISchedule Page: 310.10 Line No.Column: b
Secondary, Economy and/or non-firm sales, including some hourI firm transactions.
Schedule Page: 310.10 Line No.10 Column:
Transmission Losses
'Schedule Page: 310.10 Line No.11 Column: j
Reserve Share
ISchedule Page: 310.10 Line No.13 Column: b
Southern California Edison Com any - FERC 248 - Contract termination date: Se tember 30, 2006.
Schedule Page: 310.11 Line No.Column: b
Settlement Ad' ustment
Schedule Page: 310.11 Line No.Column: j
Settlement Adjustment
'Schedule Page: 310.11 Line No.Column: b
State of California - FERC 311 - Contract termination date: December 31, 2004.
ISchedule Page: 310.11 Line No.Column: b
Secondary, Econom and/or non-firm sales, including some hourly firm transactions.
Schedule Page: 310.11 Line No.Column:
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004/04
FOOTNOTE DATA
Transmission Losses
'Schedule Page: 310.11 Line No.Column: b
Settlement Adjustment
ISchedule Page: 310.11 Line No.10 Column: b
Secondar , Econom and/or non-firm sales, includin some hourly firm transactions.
Schedule Page: 310.11 Line No.10 Column:
eratin Reserves
Schedule Page: 310.11 Line No.11 Column: j
Transmission Losses
ISchedule Page: 310.11 Line No.13 Column: b
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
'Schedule Page: 310.12 Line No.Column: b
Utah Associated Municipal Power Systems - WSPP - Contract termination date: October 31, 2007.
jSchedule Page: 310.12 Line No.Column: b
Secondary, Economy and/or non-firm sales, including some hourly firm transactions.
'Schedule Page: 310.12 Line No.Column: j
Transmission Losses
'Schedule Page: 310.12 Line No.Column: b
Utah Munici al Power A enc - FERC 433 - Contract termination date: Jul 1,2005.
Schedule Pa e: 310.12 Line No.Column: b
Utah Munici al Power A enc - FERC 433 - Contract termination date: June 30, 2017.
Schedule Page: 310.12 Line No.Column: b
Secondary, Econom and/or non-firm sales, includin some hourI firm transactions.
Schedule Pa e: 310.12 Line No.10 Column: b
Western Area Power Administration - FERC 313 - Contract termination date: December 31 , 2004.
ISchedule Page: 310.12 Line No.11 Column: b
Seconda , Econom and/or non-firm sales, includin some hourI firm transactions.
Schedule Pa e: 310.12 Line No.12 Column:
Transmission Losses
ISchedule Page: 310.13 Line No.Column: b
Settlement Adjustment
ISchedule Page: 310.13 Line No.Column: j
Settlement Ad' ustment
Schedule Pa e: 310.13 Line No.Column:
Recognition and reporting of gains and losses on bookouts under EITF Issue No. 03-
ISchedule Page: 310.13 Line No.Column: j
Recognition and re ortin of aiDS and losses on ener y trading contracts under EITF Issue No. 02-
Schedule Page: 310.13 Line No.Column: j
Accrual Adjustment
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 320 Line No.76 Column: b
In July 2003, the Emerging Issues Task Force ("EITF") issued EITF No. 03-11. Effective January 1,2004, PacifiCorp adopted EITF
No. 03-11, which provides guidance on whether to report realized gains or losses on physically settled derivative contracts not held for
trading purposes on a gross or net basis and requires realized gains or losses on derivative contracts that do not settle physically to be
reported on a net basis. The adoption ofEITF No. 03-11 resulted in PacifiCorp s netting certain contracts that were previously
recorded on a gross basis, which reduced Sales for Resale and Purchased Power. Since PacifiCorp has a fiscal year end of March 31,
the implementation of EITF 03-11 resulted in a reclassification of $397.7 million at March 31, 2004 for the fiscal year then ended (first
quarter of the calendar year). Consequently, since FERC reporting is based on a calendar year, the financial information reported in
the following accounts contains the impact of the adjustment for the 12 month period ending March 31, 2004 as opposed to just the 3
months impact. The following table summarizes the effect of adopting EITF 03-11 on each quarter of the fiscal year ended March 31,
2004, which was all recorded in the first quarter of the calendar year (fourth quarter of the fiscal year). Adoption of EITF No. 03-
had no impact on PacifiCorp s Net income.
Sales for Resale
Purchased Power
Other Electric Revenues
QI-FY 04 Q2-FY 04 Q3-FY 04
(O2-CY 03) (O3-CY 03) (O4-CY 03)
$113,426,335 $ 82,874,255 $108,970,755
(110,706,073) (104,699,500) (90,471,134)
(2,720,262) 21,825,245 (18,499,621)
Q4-FY 04
(Ot-CY 04)
$98,740,774
(91,782,690)
958,084)
FY 2004 Total
$404,012,119
(397,659,397)
(6,352,722)
ISchedule Page: 320 Line No.158 Column: b
Pensions and benefit costs are allocated to the same account as the labor costs.
ISchedule Page: 320 Line No.158 Column: c
Pensions and benefit costs are allocated to the same account as the labor costs.
IFERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 326 Line No.Column: b
Settlement ad' ustment
Schedule Pa e: 326 Line No.Column: I
Settlement ad' ustment
Schedule Pa e: 326 Line No.Column: I
tion rernium
Schedule Page: 326 Line No.Column: b
A uila Merchant Services, Inc. - Contract Termination Date: Se tember 30, 2006.
Schedule Pa e: 326 Line No.Column: I
Option premium
Red e a out
Schedule Pa e: 326 Line No.Column: I
Gas hedge for tolling agreement.
ISchedule Page: 326 Line No.Column: I
Settlement adjustment
jSchedule Page: 326 Line No.: 10 Column: b
Arizona Public Service - Contract Termination Date: October 31, 2020.
ISchedule Page: 326 Line No.: 10 Column: I
Settlement ad' ustment
Schedule Page: 326 Line No.11 Column: b
Secondar , economy and/or non-firm.
Schedule Page: 326 Line No.11 Column: I
erating reserves
Schedule Page: 326 Line No.13 Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326 Line No.13 Column: I
erating reserves
Schedule Page: 326 Line No.14 Column: I
Reserve share
ISchedule Page: 326.Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.Line No.Column: I
Operating reserves
ISchedule Page: 326.Line No.Column: I
Gas hedge for tolling agreement.
ISchedule Page: 326.Line No.Column: I
Settlement adjustment
'Schedule Page: 326.Line No.Column: b
Under Electric Service Agreement subject to termination upon timel notification.
Schedule Page: 326.Line No.Column: I
Settlement adjustment
ISchedule Page: 326.Line No.: 10 Column: b
Settlement adjustment
ISchedule Page: 326.Line No.: 10 Column: I
eration and maintenance ex ense associated with the combustion turbine located in Rapid City, South Dakota.
Schedule Page: 326.Line No.11 Column: I
eration and maintenance ex ense associated with the combustion turbine located in Ra id City, South Dakota.
Schedule Page: 326.Line No.12 Column: b
Secondary, econom and/or non-firm.
Schedule Page: 326.Line No.14 Column: b
Secondary, economy and/or non-firm.
IFERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 326.Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.Line No.Column: I
Green tags
jSchedule Page: 326.Line No.Column: b
Bonneville Power Administration - Contract Termination Date: Au ust 31, 2011.
Schedule Page: 326.Line No.Column: b
Bonneville Power Administration - Contract Termination Date: 30 days written notice.
ISchedule Page: 326.Line No.Column: I
erating reserves
Schedule Pa e: 326.Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.Line No.Column: I
eratin reserves
Schedule Pa e: 326.Line No.Column: I
Reserve share
'Schedule Page: 326.Line No.Column: b
Settlement adjustment
'Schedule Page: 326.Line No.Column: I
Settlement adjustment
ISchedule Page: 326.Line No.10 Column: I
Non-generation agreement
'Schedule Page: 326.Line No.13 Column: b
Settlement adjustment
'Schedule Page: 326.Line No.13 Column: I
Settlement adjustment
'Schedule Page: 326.Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.Line No.Column: b
Secondar ,econom and/or non-firm.
Schedule Page: 326.Line No.Column: I
Liquidated dama es
Schedule Page: 326.Line No.Column: I
Settlement adjustment
ISchedule Page: 326.Line No.Column: I
erating ex ense, bond interest, amortization and taxes.
Schedule Page: 326.-Line No.Column: b
Secondary, economy and/or non-firm.
'Schedule Page: 326.Line No.Column: I
eratin ex ense, bond interest, amortization and taxes.
Schedule Page: 326.Line No.Column: I
Reserve share
ISchedule Page: 326.Line No.13 Column: b
Secondary, economy and/or non-firm.
'Schedule Page: 326.Line No.Column: I
Settlement adjustment
'Schedule Page: 326.4 Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.Line No.Column: I
Option premium
ISchedule Page: 326.Line No.Column: I
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
Com ensation for lost eneration at hydroelectric roject.
Schedule Pa e: 326.Line No.14 Column: I
Settlement adjustment
'Schedule Page: 326.Line No.Column: I
Operating expense, bond interest, amortization and taxes.
jSchedule Page: 326.Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.Line No.Column: I
Settlement adjustment
'Schedule Page: 326.Line No.Column: I
Reserve share
'Schedule Page: 326.Line No.Column: b
Settlement ad' ustment
Schedule Page: 326.Line No.Column: I
Settlement ad' ustment
Schedule Page: 326.Line No.13 Column: b
Second , economy and/or non-firm.
Schedule Pa e: 326.Line No.Column: b
Secondary, economy and/or non-firm.
'Schedule Page: 326.Line No.Column: b
Under Electric Service A eement subject to termination u on timely notification.
Schedule Page: 326.Line No.13 Column: b
Secondary, economy and/or non-fmn.
'Schedule Page: 326.Line No.Column: b
Under Electric Service Agreement sub'ect to termination upon timely notification.
Schedule Page: 326.Line No.Column: I
Operating expense, bond interest, amortization and taxes.
jSchedule Page: 326.Line No.Column: I
Operating expense, bond interest, amortization and taxes.
'Schedule Page: 326.Line No.Column: b
Settlement adjustment
'Schedule Page: 326.Line No.Column: I
Operating expense, bond interest, amortization and taxes.
ISchedule Page: 326.Line No.Column: b
Grant County Public Utility District No.2 - Contract Termination Date: 2 years written notice.
'Schedule Page: 326.Line No.Column: I
Ancillary services, cost recovery adjustment and rior eriod adjustment.
Schedule Page: 326.Line No.Column: b
Grant Count Public Utilit District No.2 - Contract Termination Date: 2 ears written notice.
Schedule Pa e: 326.Line No.Column: I
Settlement adjustment
'Schedule Page: 326.Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.Line No.Column: I
Operating reserves
eratin ex ense, bond interest, amortization and taxes.
Schedule Pa e: 326.Line No.Column: I
Reserve share
'Schedule Page: 326.Line No.: 10 Column: b
Secondary. economy and/or non-firm.
'Schedule Page: 326.Line No.12 Column: b
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
Under Electric Service Agreement subject to termination upon timely notification.
ISchedule Page: 326.Line No.13 Column: b
Settlement adjustment
'Schedule Page: 326.Line No.13 Column: I
Settlement adjustment
ISchedule Page: 326.Line No.14 Column:
Hermiston Generating Company, LP. operates the Hermiston Plant, and is jointly owned. The respondent owns 50.0% of the plant.
See Pa e 402.3 Column (c) of this Form No.1 for further information on the Hermiston Plant.
Schedule Pa e: 326.Line No.14 Column: I
On eak incentive, su lemental dispatch efficiency ex ense, start-u charges, committee settlements and settlement adjustment.
Schedule Pa e: 326.Line No.Column: b
Secondary, economy and/or non-firm.
'Schedule Page: 326.Line No.Column: I
Load curtailment
jSchedule Page: 326.Line No.Column: b
Seconda , economy and/or non-firm.
Schedule Pa e: 326.Line No.Column: I
Load curtailment
'Schedule Page: 326.Line No.Column: b
Hurricane, City of - Contract Termination Date: August 31, 2007.
\Schedule Page: 326.Line No.Column: I
Gas hedge for tolling a eement.
Schedule Page: 326.Line No.Column: I
Labor, equipment and administration fees associated with hydro project in Idaho Falls, Idaho.
'Schedule Page: 326.Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.Line No.Column: I
Operating reserves
ISchedule Page: 326.Line No.Column: I
Reserve share
Line loss
ISchedule Page: 326.Line No.14 Column: I
Compensation for self-generation.
'Schedule Page: 326.Line No.Column: I
Fixed annual payment
'Schedule Page: 326.Line No.Column: b
Secondar , economy and/or non-firm.
Schedule Pa e: 326.Line No.Column: I
Operating reserves
ISchedule Page: 326.Line No.Column: b
Settlement adjustment
ISchedule Page: 326.Line No.Column: I
Settlement adjustment
ISchedule Page: 326.Line No.11 Column: b
Secondar , econom and/or non-firm.
Schedule Pa e: 326.Line No.13 Column: b
Settlement ad'ustment
Schedule Pa e: 326.Line No.13 Column: I
Settlement ad' ustment
Schedule Pa e: 326.Line No.14 Column: I
Compensation for interuptible service and operating reserves.
IFERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Oa, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
'Schedule Page: 326.10 Line No.Column: b
Under Electric Service Agreement subject to termination upon timely notification.
jSchedule Page: 326.10 Line No.Column: b
Settlement adjustment
ISchedule Page: 326.10 Line No.Column: I
FERC 206 settlement
ISchedule Page: 326.10 Line No.Column: I
Option premium
Red e ayout
Schedule Page: 326.10 Line No.Column: b
Secondary, econom and/or non-firm.
Schedule Pa e: 326.10 Line No.Column: b
Under Electric Service Agreement subject to termination upon timely notification.
ISchedule Page: 326.10 Line No.10 Column: b
Settlement adjustment
'Schedule Page: 326.10 Line No.10 Column: I
Line loss
ISchedule Page: 326.10 Line No.11 Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.10 Line No.12 Column: I
Line loss
ISchedule Page: 326.10 Line No.14 Column: I
Settlement adjustment
'Schedule Page: 326.11 Line No.Column: I
Reserve share
ISchedule Page: 326.11 Line No.Column: I
erating reserves
Schedule Page: 326.11 Line No.Column: I
Gas bed e for tollin a reement.
Schedule Pa e: 326.11 Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.11 Line No.10 Column: b
Secondar "economy and/or non-firm.
Schedule 'Page: 326.11 Line No.11 Column: I
Settlement ati. ustment
Schedule Pa e: 326.11 Line No.12 Column: b
Settlement adjustment
ISchedulePage: 326.11 Line No.12 Column: I
Settlement adjustment
ISchedule Page: 326.11 Line No.14 Column: b
Settlement adjustment
ISchedule Page: 326.11 Line No.14 Column: I
Settlement adjustment
ISchedule Page: 326.12 Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.12 Line No.Column: b
Under Electric Service Agreement subject to termination upon timely notification.
ISchedule Page: 326.12 Line No.Column: b
Seconda , economy and/or non-firm.
Schedule Pa e: 326.12 Line No.Column: b
Settlement adjustment
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 326.12 Line No.Column: I
Operation expense plus amortization of unrecovered costs of Cove Project.
jSchedule Page: 326.12 Line No.Column: b
Portland General Electric Company - Contract Termination Date: Round Butte project no longer operating for power production
oses.
Schedule Pa e: 326.12 Line No.Column: I
Operation expense plus amortization of unrecovered costs of Cove Project.
ISchedule Page: 326.12 Line No.Column: I
Reserve share
'Schedule Page: 326.12 Line No.11 Column: b
Secondary, economy and/or non-firm.
'Schedule Page: 326.12 Line No.14 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
'Schedule Page: 326.13 Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.13 Line No.Column: b
Secondary, econom and/or non-fmn.
Schedule Page: 326.13 Line No.Column: I
eratin reserves
Schedule Pa e: 326.13 Line No.Column: I
Line loss
ISchedule Page: 326.13 Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.13 Line No.Column: I
Operating reserves
eratin ex ense, bond interest, amortization and taxes.
Schedule Pa e: 326.13 Line No.Column: I
Reserve share Ius line loss.
Schedule Page: 326.13 Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.13 Line No.14 Column: b
Secondary, economy and/or non-firm,
ISchedule Page: 326.14 Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.14 Line No.Column: b
Sacramento Municipal Utility District - Contract Termination Date: December 31 , 2014.
ISchedule Page: 326.14 Line No.Column: I
Settlement adjustment
ISchedule Page: 326.14 Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.14 Line No.Column: I
Line loss
ISchedule Page: 326.14 Line No.: 10 Column: b
Secondary, econom and/or non-firm.
Schedule Page: 326.14 Line No.: 10 Column: I
Operating reserves
'Schedule Page: 326.14 Line No.11 Column: I
Reserve share
ISchedule Page: 326.14 Line No.12 Column: I
Conservation & Renewables Discount a lied to wind ro ect near Arlington, Wyoming,
Schedule Page: 326.14 Line No.13 Column: I
I FERC FORM NO.1 (ED. 12-87)Page 450,
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
Li uidated dama es
Schedule Page: 326.15 Line No.Column: b
Settlement adjustment
'Schedule Page: 326.15 Line No.Column: I
Settlement adjustment
ISchedule Page: 326.15 Line No.Column: I
Gas hedge for tolling agreement.
ISchedule Page: 326.15 Line No.Column: b
Settlement adjustment
'Schedule Page: 326.15 Line No.Column: I
Line loss
jSchedule Page: 326.15 Line No.Column: b
Secondary, economy and/or non-firm.
'Schedule Page: 326.15 Line No.Column: I
Reserve share Ius line loss.
Schedule Pa e: 326.15 Line No.Column: b
Secondary, economy and/or non-firm.
jSchedule Page: 326.15 Line No.Column: I
Load curtailment
'Schedule Page: 326.15 Line No.10 Column: b
Secondary, economy and/or non-firm.
'Schedule Page: 326.15 Line No.13 Column: b
Under Electric Service Agreement sub.ect to termination u on timely notification.
Schedule Page: 326.15 Line No.14 Column: b
Under Electric Service Agreement subject to termination upon timel notification.
Schedule Page: 326.16 Line No.Column: b
Under Electric Service Agreement subject to termination u on timely notification.
Schedule Page: 326.16 Line No.Column: I
Settlement adjustment
ISchedule Page: 326.16 Line No.Column: b
Settlement adjustment
\Schedule Page: 326.16 Line No.Column: I
Settlement adjustment
ISchedule Page: 326.16 Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.16 Line No.Column: I
Operating reserves
ISchedule Page: 326.16 Line No.Column: I
Reserve share
'Schedule Page: 326.16 Line No.Column: b
Settlement adjustment
ISchedule Page: 326.16 Line No.Column: I
Settlement adjustment
'Schedule Page: 326.16 Line No.10 Column: b
Transalta Energy Marketing Corp. - Contract Termination Date: June 30, 2007.
ISchedule Page: 326.16 Line No.10 Column: I
Liquidated damages
eratin reserve reimbursment.
Schedule Pa e: 326.16 Line No.12 Column: b
Tri-State Generation & Transmission - Contract Termination Date: December 31 , 2020.
ISchedule Page: 326.16 Line No.13 Column: b
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
Secondary, economy and/or non-firm.
ISchedule Page: 326.17 Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.17 Line No.Column: b
Secondary, economy and/or non-firm.
ISchedule Page: 326.17 Line No.Column: b
Secondary, economy and/or non-flfm.
ISchedule Page: 326.17 Line No.10 Column: b
Under Electric Service Agreement subject to termination upon timely notification.
ISchedule Page: 326.17 Line No.11 Column: b
Settlement adjustment
ISchedule Page: 326.17 Line No.11 Column: I
Settlement adjustment
Line loss
ISchedule Page: 326.17 Line No.12 Column: b
Secondar , economy and/or non-fmn.
Schedule Page: 326.17 Line No.12 Column: I
erating reserves
Schedule Page: 326.17 Line No.13 Column: I
Line loss
'Schedule Page: 326.18 Line No.Column: I
Accounting accrual and excess net power cost deferrals.
jSchedule Page: 326.18 Line No.Column: b
Settlement adjustment
ISchedule Page: 326.18 Line No.Column: I
Recognition and reporting of gains and losses on bookouts under EITF Issue No. 03-11.
ISchedule Page: 326.18 Line No.Column: I
Recognition and reporting of gains and losses on bookouts under EITF Issue No. 03-11.
ISchedule Page: 326.18 Line No.Column: I
Reserve for potential liabilities associated with Rock River 1, liquidated damages and line losses.
'Schedule Page: 326.18 Line No.Column: I
Recognition and re ortin of ains and losses on energy trading contracts under EITF Issue No. 02-04.
Schedule Page: 326.19 Line No.Column: I
Exchange energy expense.
ISchedule Page: 326.19 Line No.Column: I
Load factorin and stora e char es.
Schedule Page: 326.19 Line No.Column: I
Exchange ener expense.
Schedule Page: 326.19 Line No.Column: I
Imbalance ener
Schedule Page: 326.19 Line No.11 Column: I
Exchan e ener expense.
Schedule Page: 326.19 Line No.12 Column: I
Imbalance ener
Schedule Page: 326.19 Line No.13 Column: I
Load factoring and storage charges.
ISchedule Page: 326.19 Line No.14 Column: c
Pacific Northwest Electric Power Planning and Conservation Act, FERC Electric Tariff, Original Volume No.
'Schedule Page: 326.19 Line No.14 Column: h
These Megawatt Hours represent book entry only. No actual energy transfer took place.
ISchedule Page: 326.19 Line No.14 Column: i
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Oa, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
These Megawatt Hours re resent book entry only. No actual energ transfer took lace.
Schedule Pa e: 326.19 Line No.14 Column: I
Pacific Northwest Electric Power Plannin and Conservation Act, FERC Electric Tariff, Ori inal Volume No.
Schedule Pa e: 326.20 Line No.Column: I
Exchange energy expense and storage charges.
ISchedule Page: 326.20 Line No.Column: I
Exchange energy expense.
ISchedule Page: 326.20 Line No.Column: I
Exchange energy expense and storage charges.
ISchedule Page: 326.20 Line No.Column: I
Load factorin and stora e char es.
Schedule Page: 326.20 Line No.Column: I
Exchange ener y ex ense.
Schedule Pa e: 326.20 Line No.Column: I
Imbalance ener
Schedule Pa e: 326.20 Line No.11 Column:
PPM Ener is an affiliate of the res ondent.
Schedule Pa e: 326.20 Line No.11 Column: I
Imbalance energy
'Schedule Page: 326.20 Line No.13 Column: I
Exchange energy ex ense.
Schedule Page: 326.21 Line No.Column: I
Exchange ener ex ense.
Schedule Page: 326.21 Line No.Column: I
Exchange ener y ex ense.
Schedule Page: 326.21 Line No.Column: I
Exchange energy expense.
Imbalance ener
Schedule Pa e: 326.21 Line No.Column: I
Imbalance energy
'Schedule Page: 326.21 Line No.Column: I
Imbalance ener y
Schedule Page: 326.21 Line No.Column: b
Not applicable: adjustment for inadavertant interchange.
I FERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
!Schedule Page: 328 Line No.Column: d
Ever reen Network Transmission Service under the 0 en Access Transmission Tariff (S.A. 228 & 233).
Schedule Pa e: 328 Line No.Column: d
Evergreen Network Transmission Service under the Open Access Transmission Tariff (S.A. 228 & 233).
ISchedule Page: 328 Line No.Column:
Charges for monitoring, scheduling, load following and spinning reserve.
ISchedule Page: 328 Line No.Column: d
Dave Johnston Substation operation and maintenance.
ISchedule Page: 328 Line No.Column:
eration and Maintenance Char es
Schedule Pa e: 328 Line No.Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328 Line No.Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
'Schedule Page: 328 Line No.Column: d
Non-Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
'Schedule Page: 328 Line No.Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
'Schedule Page: 328 Line No.Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
'Schedule Page: 328 Line No.Column: d
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various arties and points.
Schedule Page: 328 Line No.Column: d
Network Transmission Service under the 0 en Access Transmission Tariff (S.A. 67) terminating on December 31, 2006.
Schedule Page: 328 Line No.Column: d
Point-to-Point Transmission Service under the 0 en Access Transmission Tariff (S.A. 67) terminatin on December 31, 2023.
Schedule Page: 328 Line No.Column: d
Wyodak Substation use of facilities.
'Schedule Page: 328 Line No.Column:
Sole use of facilities charge.
ISchedule Page: 328 Line No.Column: d
General Transfer A reement for network service in PACW. Ever reen
Schedule Pa e: 328 Line No.Column:
Sole use of facilities char e.
Schedule Page: 328 Line No.10 Column:
Network Transmission Service terminating on October 31, 2008.
'Schedule Page: 328 Line No.10 Column:
Demand dollars Ius a fixed cost calculated usin lant investment values at various U.S. overnment facilities.
Schedule Page: 328 Line No.11 Column: d
General Transfer A reement for network service in PACE. Ever een
Schedule Pa e: 328 Line No.12 Column:
South Idaho Exchan e A eement. Sub'ect to Termination u on written notification.
Schedule Pa e: 328 Line No.12 Column:
Charges for monitorin , scheduling, load following and spinning reserve.
Schedule Page: 328 Line No.13 Column: d
Point-to-Point Transmission Service under the 0 en Access Transmission Tariff (S.A. 179) terminating on September 30, 2005.
Schedule Pa e: 328 Line No.13 Column:
Char es for monitorin , scheduling, load followin and s innin reserve.
Schedule Page: 328 Line No.14 Column: d
Network Transmission Service and Distribution Delivery Service under the Open Access Transmission Tariff (S.A. 229) terminating
on September 30, 2011.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 328 Line No.14 Column:
Demand dollars plus a fixed cost calculated using plant investment values at various U.S. government facilities.
Distribution Service Char e
Schedule Page: 328 Line No.15 Column: b
Various signatories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.15 Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328 Line No.15 Column: d
Non-Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
ISchedule Page: 328 Line No.16 Column: d
Blacksfork Substation operation and maintenance.
ISchedule Page: 328 Line No.16 Column:
Operation and Maintenance Charges
ISchedule Page: 328 Line No.17 Column: b
Various signatories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.17 Column:
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328 Line No.17 Column: d
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various
Schedule Page: 328.Line No.Column: b
Various signatories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
'Schedule Page: 328.Line No.Column: d
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various arties and points.
Schedule Page: 328.Line No.Column: b
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.Line No.Column: d
Non-Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
ISchedule Page: 328.Line No.Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.Line No.Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.Line No.Column: d
Non-Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
'Schedule Page: 328.Line No.Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.Line No.Column: d
Transmission Service and 0 ratin Agreement for network service in PACE. Sub' ect to termination upon mutual agreement.
Schedule Pa e: 328.Line No.Column:
Charges for monitoring, scheduling, load followin and spinnin reserve.
Schedule Page: 328.Line No.Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.Line No.Column: d
Transmission Service and Operatin Agreement for network service in PACE. Subject to termination u on mutual agreement.
Schedule Pa e: 328.Line No.Column:
Settlement adjustment
ISchedule Page: 328.Line No.Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
I FERC FORM NO.1 (ED. 12-Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmisslon 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 328.Line No.Column:
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.Column:
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various arties and points.
Schedule Pa e: 328.Line No.Column: b
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Pa e: 328.Line No.Column:
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Pa e: 328.Line No.Column:
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various
Schedule Pa e: 328.Line No.Column:
Point-to-Point Transmission Service terminatin on July 31 2028.
Schedule Page: 328.Line No.Column:
Evergreen Network Transmission Service and Distribution Delivery Service under the Open Access Transmission Tariff (S.A. 227).
ISchedule Page: 328.Line No.Column:
Network Integration transmission service.
Char es for monitorin , scheduling, load followin and s innin reserve.
Schedule Pa e: 328.Line No.: 10 Column:
Point-to-Point Transmission Service under the Open Access Transmission Tariff (S.A. 212) terminating on May 31,2006.
'Schedule Page: 328.Line No.12 Column: b
Various si natories to the Ori inal Volume 11 Point -to-Point Transmission Tariff.
Schedule Page: 328.Line No.12 Column:
Various signatories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Pa e: 328.Line No.12 Column:
Non-Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
'Schedule Page: 328.Line No.13 Column:
Antelope Substation use of facilities.
'Schedule Page: 328.Line No.13 Column:
Sole use of facilities charge.
'Schedule Page: 328.Line No.14 Column:
Jim Brid er Pum use of facilities.
Schedule Pa e: 328.Line No.14 Column:
Sole use of facilities charge.
ISchedule Page: 328.Line No.15 Column: b
VariOus si natories to the Original Volume 11 Point-to-Point Transmission Tariff.
Schedule Pa e: 328.Line No.15 Column:
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.1. Line No.15 Column:
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various
Schedule Pa e: 328.Line No.16 Column:
Transmission Service and Interconnection A eement for network service in PACE. Terminates in 2047
Schedule Pa e: 328.Line No.17 Column: b
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.17 Column:
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Pa e: 328.Line No.Column: b
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Pa e: 328.Line No.Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
~hedule Page: 328.Line No.Column:
Non-Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
'Schedule Page: 328.Line No.Column: d
Malin to Indian S rin s use of facilities Terminatin Au ust 1, 2007.
Schedule Page: 328.Line No.Column: d
Pinto Phase Shifter use of facilities and a eration and maintenance char es terminatin
Schedule Pa e: 328.Line No.Column:
Char es for monitorin , schedulin , load followin and s innin reserve.
Schedule Page: 328.Line No.Column:
PPM Energy is an affiliate of the res ondent.
Schedule Page: 328.Line No.Column: d
Point-to-Point Transmission Service under the 0 en Access Transmission Tariff (S.A. 218)
Schedule Page: 328.Line No.Column:
PPM Energy is an affiliate of the respondent.
ISchedule Page: 328.Line No.Column: d
Point-to-Point Transmission Service under the 0 en Access Transmission Tariff (S.A. 278)
Schedule Page: 328.Line No.Column:
PPM Energy is an affiliate of the respondent.
ISchedule Page: 328.Line No.Column: d
Point-to-Point Transmission Service under the Open Access Transmission Tariff (S.A. 279)
!Schedule Page: 328.Line No.Column:
PPM Energy is an affiliate of the respondent.
ISchedule Page: 328.Line No.Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.Line No.Column: c
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.Line No.Column: d
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various parties and oints.
Schedule Page: 328.Line No.Column:
PPM Ener y is an affiliate of the respondent.
Schedule Page: 328.Line No.Column: b
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.Column: c
Various signatories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.Column: d
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various arties and points.
Schedule Pa e: 328.Line No.Column: d
Dalreed Substation use or facilities, 0 eration and maintenance.
Schedule Page: 328.Line No.Column:
Sole use of facilities charge.
ISchedule Page: 328.Line No.: 10 Column: d
Harrison Substation use of facilities.
ISchedule Page: 328.Line No.: 10 Column:
Sale use of facilities charge.
ISchedule Page: 328.Line No.12 Column: d
Point-to-Point Transmission Service under the 0 en Access Transmission Tariff (S.A. 169) terminating on September 30, 2007.
Schedule Pa e: 328.Line No.13 Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
!Schedule Page: 328.Line No.13 Column: c
Various signatories to the Original Volwne 11 Point-to-Point Transmission Tariff.
'Schedule Page: 328.Line No.13 Column: d
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various
Schedule Pa e: 328.Line No.14 Column: b
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
Various signatories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.14 Column:
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.14 Column: d
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various arties and points.
Schedule Page: 328.Line No.15 Column: b
Various si natories to the Original Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.15 Column:
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Pa e: 328.Line No.15 Column: d
Non-Finn Transmission Service under the 0 en Access Transmission Tariff between various parties and points.
Schedule Page: 328.Line No.16 Column: b
Various si natories to the Original Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.16 Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
'Schedule Page: 328.Line No.16 Column: d
Non-Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
ISchedule Page: 328.Line No.17 Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
jSchedule Page: 328.Line No.17 Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.Line No.17 Column: d
Non-Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
'Schedule Page: 328.Line No.17 Column:
Settlement adjustment
ISchedule Page: 328.Line No.Column: b
Various signatories to the Od inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.Column:
Various signatories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.Column: d
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various
Schedule Page: 328.Line No.Column: d
Malin to Indian S rin s use of facilities Terminatin Au ust 1, 2007.
Schedule Pa e: 328.Line No.Column:
Sole use of facilities char e.
Schedule Page: 328.Line No.Column: b
Various signatories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.Line No.Column: d
Transmission Service and Use of facilities A reement terminatin July 31, 2014.
Schedule Page: 328.Line No.Column:
Sole use of facilities charge.
'Schedule Page: 328.Line No.Column: b
Various signatories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.Column:
Various signatories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Pa e: 328.Line No.Column: d
Non-Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
ISchedule Page: 328.Line No.Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
I FERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1 ) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
jSchedule Page: 328.Line No.Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
jSchedule Page: 328.Line No.Column: d
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various
Schedule Page: 328.Line No.Column: d
Buffalo Substation distribution delivery service.
'Schedule Page: 328.Line No.Column:
Sole use of facilities char e.
Schedule Page: 328.Line No.Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.Line No.Column:
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.Column:
Operation and Maintenance Char es
Schedule Page: 328.Line No.Column: b
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Page: 328.Line No.Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.Line No.Column: d
Non-Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
jSchedule Page: 328.Line No.Column: d
Malin to Indian S rin s use of facilities Terrninatin Au ust 1, 2007.
Schedule Pa e: 328.Line No.: 10 Column: d
Pinto Phase Shiffer use of facilities and 0 eration and maintenance char es terminatin
Schedule Pa e: 328.Line No.: 10 Column:
Char es for monitorin , scheduling, load followin and s inning reserve.
Schedule Page: 328.Line No.11 Column: d
Point-to-Point Transmission Service under the 0 en Access Transmission Tariff (S.A. 170) terminating on May 31, 2005.
Schedule Pa e: 328.Line No.12 Column: b
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Pa e: 328.Line No.12 Column:
Various si atories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Pa e: 328.Line No.12 Column: d
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various parties and points.
SchedulePa e: 328.Line No.13 Column: b
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Pa e: 328.Line No.Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
'Schedule Page: 328.Line No.13 Column: d
Non-Firm Transmission Service under the Open Access Transmission Tariff between various parties and points.
'Schedule Page: 328.Line No.14 Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
'Schedule Page: 328.Line No.14 Column:
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
'Schedule Page: 328.Line No.15 Column: d
Transmission Service Agreement for Network Services in PACE Terminating upon written notification.
'Schedule Page: 328.Line No.15 Column:
eration and Maintenance Char es
Schedule Pa e: 328.Line No.16 Column: d
Transmission Service A eement for Network Services in PACE Terminating upon written notification.
Schedule Pa e: 328.Line No.16 Column:
I FERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
eration and Maintenance Charges
Schedule Pa e: 328.Line No.17 Column: d
Transmission Service Agreement for Network Services in PACE Terminating upon written notification.
'Schedule Page: 328.Line No.17 Column:
eration and Maintenance Charges
Schedule Pa e: 328.Line No.Column: d
Transmission Service A eement for Network Services in PACE Terminating upon written notification.
Schedule Page: 328.Line No.Column:
Operation and Maintenance Charges
Settlement ad' ustment
Schedule Pa e: 328.Line No.Column: d
Transmission Service Agreement for Network Services in PACE Terminating upon written notification.
ISchedule Page: 328.Line No.Column:
Imbalance ener y
Schedule Page: 328.4 Line No.Column: d
Transmission Service Agreement for network service in PACW. Under transfer agreement subject to termination when easement from
United States for transmission line between Redmond, Ore on and Prineville, Ore on is removed.
Schedule Pa e: 328.Line No.Column:
Sole use of facilities char e.
Schedule Pa e: 328.Line No.Column: d
Transmission Service Agreement for network service in P ACW.
'Schedule Page: 328.Line No.Column:
Settlement ad' ustment
Schedule Page: 328.4 Line No.Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.Line No.Column: d
Transmission Service and Operating Agreement for network service in PACE. Subject to termination upon mutual agreement.
ISchedule Page: 328.Line No.Column:
Charges for monitoring, scheduling, load following and spinning reserve.
Settlement ad' ustment
Schedule Pa e: 328.Line No.Column: b
Various signatories to the Original Volume II Point-to-Point Transmission Tariff.
ISchedule Page: 328.Line No.Column: d
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various parties and points.
Schedule Page: 328.Line No.Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
'Schedule Page: 328.Line No.Column: d
Transmission Service and 0 erating Agreement for network service in PACE. Sub' ect to termination u on mutual agreement.
Schedule Pa e: 328.4 Line No.Column:
Char es for monitorin , schedulin , load followin and spinnin reserve.
Schedule Pa e: 328.Line No.Column: b
Various signatories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Pa e: 328.Line No.Column:
Various si natories to the Ori inal Volume 11 Point-to-Point Transmission Tariff.
Schedule Pa e: 328.Line No.Column: d
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various
Schedule Pa e: 328.Line No.Column: d
Pelton Re-Re Dam Use of Facilities terminatin Januar 1 2032
Schedule Page: 328.Line No.10 Column: d
Transmission Service and Interconnection Agreement for network service in PACE. Terminates in 2047
ISchedule Page: 328.Line No.10 Column:
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
Station Service
ISchedule Page: 328.Line No.11 Column: b
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
'Schedule Page: 328.Line No.11 Column: c
Various signatories to the Original Volume 11 Point-to-Point Transmission Tariff.
ISchedule Page: 328.4 Line No.11 Column: d
Non-Firm Transmission Service under the 0 en Access Transmission Tariff between various parties and oints.
Schedule Page: 328.Line No.12 Column: d
Evergreen Network Transmission Service under the 0 en Access Transmission Tariff (S.A. 175).
Schedule Page: 328.Line No.12 Column:
Distribution Service Charge
ISchedule Page: 328.4 Line No.13 Column:
eration and Maintenance Char es
Schedule Page: 328.Line No.14 Column: d
Thermo otis Substation 0 eration and maintenance.
Schedule Page: 328.Line No.14 Column:
eration and Maintenance Char es
Schedule Page: 328.Line No.15 Column: d
Transmission Service and Operating Agreement for network service in PACE. Evergreen.
I FERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
'Schedule Page: 332 Line No.Column: g
Ancillary services
'Schedule Page: 332 Line No.Column: g
Ancillary services
Use of Facilities
'Schedule Page: 332 Line No.Column: g
Use of Facilities
'Schedule Page: 332 Line No.Column: g
Settlement adjustment
ISchedule Page: 332 Line No.12 Column: g
Ancillary services
Use of Facilities
!Schedule Page: 332 Line No.13 Column: g
Use of Facilities
'Schedule Page: 332 Line No.16 Column: g
Ancillary services
Use of Facilities
'Schedule Page: 332.Line No.Column: g
Ancill services
Schedule Pa e: 332.Line No.Column: g
Ancillar services
Schedule Pa e: 332.Line No.Column:
Use of Facilities
'Schedule Page: 332.Line No.: 10 Column: g
Res ondent's ortion of s ecified costs of certain facilities
Schedule Pa e: 332.Line No.13 Column: g
Ancillary services
Respondent's portion of specified costs of certain facilities
Use of facilities
ISchedule Page: 332.Line No.15 Column: g
Ancillary services
ISchedule Page: 332.Line No.Column: g
Membershi Fees - Transmission service char es and administration fees
Schedule Page: 332.Line No.Column:
Membership Fees - Transmission service char es and administration fees
Schedule Page: 332.Line No.Column: g
Ancillary services
'Schedule Page: 332.Line No.Column: g
Use of Facilities
ISchedule Page: 332.Line No.Column: g
Use of Facilities
ISchedule Page: 332.Line No.Column: g
Use of Facilities
ISchedule Page: 332.Line No.Column: g
Ancillary services
Res ondent'ortion of s ecified costs of certain facilities
Schedule Pa e: 332.Line No.: 10 Column:
Ancillary services
Respondent's ortion of s ecified costs of certain facilities
Schedule Pa e: 332.Line No.12 Column: g
Respondent's portion of specified costs of certain facilities
I FERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 332.Line No.14 Column: 9
Use of Facilities
Res ondent's ortion of s ecified costs of certain facilities
Schedule Pa e: 332.Line No.Column:
Ancillary services
Use of Facilities
Res ondent's ortion of s ecified costs of certain facilities
Schedule Pa e: 332.Line No.Column:
Ancillary services
ISchedule Page: 332.Line No.Column: 9Ancill services
Schedule Pa e: 332.Line No.10 Column:
Ancillary services
ISchedule Page: 332.Line No.12 Column: 9
Ancillary services
ISchedule Page: 332.Line No.15 Column: 9
Use of Facilities
ISchedule Page: 332.4 Line No.Column: 9
Ancillary services
'Schedule Page: 332.Line No.Column: 9
Ancillary services
'Schedule Page: 332.Line No.Column: 9
Ancillary services
'Schedule Page: 332.Line No.: 8 Column:
Energy reported uarterl is now disclosed on a net basis in the exchan e section of
Schedule Page: 332.Line No.: 8 Column: d
Energy reported uarterly is now disclosed on a net basis in the exchange section of
Schedule Page: 332.Line No.11 Column: 9
Ancillary services
Use of Facilities
ISchedule Page: 332.Line No.13 Column: 9
Accrual adjustment
a es 326-327.
ages 326-327.
I FERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 336 Line No.11 Column: b
Vehicle depreciation expense is allocated to the same account as the labor costs it is associated with.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 04/25/2005 2004/04
FOOTNOTE DATA
ISchedule Page: 350 Line No.
This amount is deferred to account 186.
Column:
I FERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
'Schedule Page: 400 Line No.17 Column: b
The Monti Peak numbers in rior uarters, which were reviousl estimated, have been trued-u to reflect actual data for the ear.
Schedule Pa e: 400 Line No.17 Column:
Reflects actual demands of control area load at time of Transmission S stem Peak.
Schedule Pa e: 400 Line No.17 Column:
Reflects actual demands of control area load at time of Transmission System Peak.
ISchedule Page: 400 Line No.17 Column: g
Reflects reservations in effect at time of Transmission S stem Peak.
Schedule Pa e: 400 Line No.17 Column: h
Reflects reservations in effect at time of Transmission S stem Peak.
Schedule Page: 400 Line No.17 Column: i
Reflects reservations in effect at time of Transmission System Peak.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmisslon 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 402 Line No.Column:
Cholla Plant is operated by Arizona Public Service Company. Respondent owns Unit No.4 plus 37.44% of related common facilities.
Data re orted re resents res ondent's share. PacifiCo does not have em 10 ees at the Cholla Plant.
Schedule Pa e: 402 Line No.Column: d
Colstrip Plant is operated by PPL Montana, LLC and is jointly owned. Data reported represents respondent's 10% share of Colstrip
Plant Units No.3 and No.4. PacifiCo does not have em 10 ees at the Colstri Plant.
Schedule Pa e: 402 Line No.Column:
Craig Plant is operated by Tri-State Generation and Transmission Association and is jointly owned. Data reported represents
respondent s 19.28% share of Craig Plant Units No.1 and No., and 12.86% of common facilities. PacifiCorp does not have
em 10 res at the Crai Plant.
Schedule Pa e: 402.Line No.Column: b
Hayden Plant is operated by Public Service Company of Colorado and is jointly owned. Data reported represents respondent's 24.
(45 MW) share of Hayden Unit No.1, 12.6% (33 MW) share of Hayden Unit No., and 17.5% of common facilities. PacifiCorp does
not have em 10 ees at the Ha den Plant.
Schedule Pa e: 402.Line No.Column:
Hunter Plant Unit No.1 is owned by respondent and Provo City Corporation with undivided interest of93.75% and 6.25%
respectively. Data re orted in column (c) re resents res ondent's share.
Schedule Page: 402.Line No.Column: d
Hunter Plant Unit No.2 is owned by respondent, Deseret Power Electric Cooperative, and Utah Associated Municipal Power Systems,
each with undivided interest of 60.31 %,25.108%, and 14.582% respectively. Data reported in column (d) represents respondent's
share.
ISchedule Page: 402.Line No.Column: f
Hunter Unit No.1 is owned by respondent and Provo City Corporation with undivided interest of 93.75% and 6.25% respectively.
Hunter Unit No.2 is owned by respondent, Deseret Power Electric Cooperative, and Utah Associated Municipal Power Systems, each
with undivided interest of 60.31 %,25.108%, and 14.582% res ectivel . Data in column (f) re resents res ondent's share.
Schedule Pa e: 402.Line No.Column:
Jim Bridger Plant is operated by PacifiCorp and column (c) represents the respondent's share. Ownership of the plant is as follows:
PacifiCorp 66 2/3%, Idaho Power Company 33 1/3%.
ISchedule Page: 402.Line No.Column:
Wyodak Plant is operated by PacifiCorp and column (e) represents the respondent's share. Ownership of the plant is as follows:
PacifiCo 80%, Black Hills Co oration 20%.
Schedule Page: 402.Line No.Column:
Hermiston Plant is operated by Hermiston Operating Company, LP. and is jointly owned. Data reported on lines 5 through 43
represent's the respondent's 50.0% share of the Hermiston Plant. See Page 326.7 Row 14 of this Form No.1 for further information on
Hermiston Generating Compan , LP.
Schedule Page: 402.Line No.Column:
PacifiCorp owns the steam turbine generator and associated systems directly related to the operation of this unit at Georgia-Pacific
Corporation s Camas, Washington paper mill. Modifications and upgrades to the existing Camas paper mill were necessary to supply
steam to the turbine and to ensure continued operation of the unit in the event of mill closure. Georgia-Pacific retained ownership of
these modifications. Georgia-Pacific supplies the fuel and delivers the steam to PacifiCorp s turbine. PacifiCorp is responsible for
major maintenance costs only on the repair of the turbine generator and auxiliary equipment. None of the facilities are jointly owned.
Each asset is wholly owned, either by PacifiCorp or Georgia-Pacific Corporation. PacifiCorp does not have employees at the CamasPa er Mill.
Schedule Pa e: 402.Line No.Column: f
In May 2002, PacifiCorp entered into a I5-year operating lease for an electric generation facility with West Valley Leasing Company,
LLC ("West V alley ). West Valley is a subsidiary of PPM Energy, Inc. ("PPM"), which is a direct subsidiary of PHI and an indirect
subsidiary of ScottishPower. The facility consists of five generation units, each rated at 40 megawatts ("MW"), and is located in Utah.
The lease terms granted PacifiCorp two independent early termination options that provide PacifiCorp the right to terminate the lease
and, at PacifiCorp s further option, to purchase the facility for predetermined amounts. On May 28, 2004, PacifiCorp exercised its first
option to terminate the West Valley lease. PacifiCorp subsequently exercised its right to rescind the termination on September 28,
2004 after determining, through a public process, that the resource could not be replaced on a more economic basis and without
I FERC FORM NO.1 (ED. 12-87) Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
increasing risks to system reliability. PacifiCorp has a second option to terminate the West Valley lease if written notice is provided to
West Valley on or before December 1,2006. PacitiCorp is committed to future minimum lease payments of $15.0 million annually for
years ending March 31, 2005 through 2008 and $2.5 million for the year ending March 31,2009.
IFERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 406 Line No.Column: d
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302 Franchises and Consents and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31, 2004 was $67,519,056: Lemolo 1, Lemolo 2, Clearwater 1,
Clearwater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.
ISchedule Page: 406 Line No.Column:
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302 Franchises and Consents and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31, 2004 was $67,519,056: Lemolo 1, Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda S rin s, Slide Creek and the North Urn ua Common Plant.
Schedule Pa e: 406 Line No.Column: f
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents and are not re orted on this a e. The net book value for relicensin at December 31, 2004 was $1 400,649.
Schedule Pa e: 406 Line No.Column: b
Ponda e for eakin - stora e, U er Klamath Lake.
Schedule Pa e: 406 Line No.Column:
Stora e, U er Klamath Lake.
Schedule Pa e: 406 Line No.Column: d
Foreba for eakin .
Schedule Pa e: 406 Line No.Column:
Foreba for eakin .
Schedule Pa e: 406.Line No.Column: b
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302 Franchises and Consents and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31, 2004 was $67,519,056: Lemolo 1 , Lemolo 2, Clearwater 1
Clearwater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.
'Schedule Page: 406.Line No.Column:
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302 Franchises and Consents and are not reported on this page. The net book value for relicensing and settlement on the Bear
River system for the following projects at December 31, 2004 was $16,940,164: Grace, Cove, Oneida and Soda.
'Schedule Page: 406.Line No.Column: f
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302 Franchises and Consents and are not reported on this page. The net book value for relicensing and settlement on the
North Ump~ua River"system for the following projects at December 31, 2004 was $67,519,056: Lemolo 1, Lemolo 2, Clearwater 1,
Clearwater 2, Toketee, Fish Creek, Soda S rings, Slide Creek and the North Urn ua Common Plant.
Schedule Page: 406.Line No.Column: b
Foreba for eakin .
Schedule Pa e: 406.Line No.Column: d
Stora e for re lation.
Schedule Pa e: 406.Line No.Column:
Ponda e for eakin - stora e, U er Klamath Lake.
Schedule Pa e: 406.Line No.Column: f
Stora e, Lemolo Lake.
Schedule Pa e: 406.Line No.Column: b
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302 Franchises and Consents and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31, 2004 was $67,519,056: Lemolo 1, Lemolo 2, Clearwater 1,
Clearwater 2, Toketee, Fish Creek, Soda S rin s, Slide Creek and the North Urn qua Common Plant.
Schedule Page: 406.Line No.Column:
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents and are not reported on this page. The net book value for relicensing at December 31, 2004 was $292,807.
I FERC FORM NO.1 (ED. 12-87) Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmisslon 04/25/2005 2004/04
FOOTNOTE DATA
Schedule Pa e: 406.Line No.Column: d
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302 Franchises and Consents and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31 , 2004 was $67,519,056: Lemolo 1, Lemolo 2, Clearwater 1,
Clearwater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.
ISchedule Page: 406.Line No.Column:
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302 Franchises and Consents and are not reported on this page. The net book value for relicensing and settlement on the Bear
River system for the followin rojects at December 31, 2004 was $16,940,164: Grace, Cove, Oneida and Soda.
Schedule Page: 406.Line No.Column:
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents and are not reported on this page. The net book value for relicensing at Prospect unit numbers 1, 2, 3 & 4 at
December 31, 2004 was $137,304.
ISchedule Page: 406.Line No.Column: b
Storage, Lemolo Lake.
ISchedule Page: 406.Line No.Column: d
Ponda e for eakin - stora e, Lemolo Lake.
Schedule Pa e: 406.Line No.Column:
Foreba for eakin .
Schedule Pa e: 406.Line No.Column: b
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302 Franchises and Consents and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31 , 2004 was $67,519,056: Lemolo 1 , Lemolo 2, Clearwater 1,
Clearwater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.
ISchedule Page: 406.Line No.Column: c
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302 Franchises and Consents and are not reported on this page. The net book value for relicensing and settlement on the Bear
River system for the following projects at December 31, 2004 was $16,940,164: Grace, Cove, Oneida and Soda.
'Schedule Page: 406.Line No.Column: d
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302 Franchises and Consents and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31, 2004 was $67,519,056: Lemolo 1, Lemolo 2, Clearwater 1,
Clearwater 2, Toketee, Fish Creek, Soda Sprin s, Slide Creek and the North Urn ua Common Plant.
Schedule Page: 406.Line No.Column:
Costs reported for this plant do not include significant intangible costs due torelicensing which are recorded in FERC account 302
Franchises and Consents and are not re orted on this a e. The net book value for relicensin at December 31 , 2004 was $39,844.
Schedule Pa e: 406.Line No.Column:
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents and are not re orted on this a e. The net book value for relicensin at December 31, 2004 was $40,656.
Schedule Pa e: 406.Line No.Column: b
Olmstead Plant is owned by the U.S. Bureau of Land Reclamation. PacifiCorp has a 25 year lease beginning in 1990. The respondent
operates the plant and owns the generation.
IFERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 410 Line No.Column:
Common river s stem costs for the 0 eration of these facilities are allocated to each
Schedule Pa e: 410 Line No.Column:
The FERC issued a surrender order for American Fork on August 4, 2004, which calls for project removal to be completed by
December 2007. Removal costs for this 1.0 MW project are estimated to be approximately $1.1 million, including process and
permitting costs. The parties have agreed that project removal will begin in September 2006, subject to FERC and other regulatory
a provals, with operations continuing until that time.
Schedule Page: 410 Line No.Column:
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents and are not reported on this page. The net book value for relicensing at December 31 2004 was $225 692.
This cost of lant balance includes $1 036,326 of American Fork asset retirement costs.
Schedule Pa e: 410 Line No.Column:
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents and are not reported on this page. The net book value for relicensin at December 31, 2004 was $431,585.
Schedule Pa e: 410 Line No.Column:
PacifiCorp and six other minority owners sold their interest in the 1 MW Skookumchuck Hydroelectric project to a subsidiary of
Alberta Based TransAlta for $7.4 million. PacifiCorp s share was $3.5 million. The sale was completed on October 5th, 2004, with
the proceeds, net book value, and selling costs transferred to FERC account 102. Additional closing costs were booked in December
2004 and cleared to FERC account 102. A letter to FERC for ermission to clear account 102 is pending.
Schedule Page: 410 Line No.Column:
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents and are not reported on this page. The net book value for relicensing at December 31 , 2004 was $610,941.
ISchedule Page: 410 Line No.Column:
In September 1999, a settlement agreement to remove the 9.6 MW Condit hydroelectric project was signed by PacifiCorp, state and
federal agencies, and non-governmental agencies, which called for removal to begin in October 2006 for a total cost to decommission
not to exceed $17.2 million, excluding inflation. On February 3, 2005, the parties agreed to modify the settlement agreement so that
removal will not begin until October 2008 for a total cost to decommission not to exceed $20.5 million, excluding inflation. The
settlement agreement is contingent upon receiving a consistent FERC order and other regulatory approvals. PacifiCorp is in the
process of ac uirin all necess ermits, within the terms and conditions of the settlement a reement.
Schedule Page: 410 Line No.10 Column:
Licensed Project No, 2401 applicable to both Cove and Grace Plants (see page 406 for Grace plant). The FERC included in the Bear
River s license a requirement to evaluate decommissioning the 7.5 MW Cove plant and associated project features. As part of this
evaluation, PacifiCo has been workin with stakeholders to determine the actions that would be re uired to decommission this lant.
Schedule Pa e: 410 Line No.10 Column:
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302 Franchises and Consents and are not reported on this page. The net book value for relicensing and settlement on the Bear
River s stem for the followin ro ects at December 31, 2004 was $16,940,164: Grace, Cove, Oneida and Soda.
Schedule Pa e: 410 Line No.11 Column:
PacifiCorp has sold the Naches and Naches Drop Hydroelectric Plants to the United States Bureau of Reclamation. Water Rights
along with some buildings and equipment were turned over to the Bureau of Reclamation on March 10,2003. Access to the remainder
of the building and equipment was granted to the United States Bureau of Reclamation effective January 1,2004. The third
amendment to the water rights purchase agreement was executed November I, 2004. Transfer of the land rights per this agreement
occurred on March 31,2005. A letter to the FERC for ermission to clear FERC account 102 has been a roved.
Schedule Pa e: 410 Line No.19 Column:
PacifiCorp has sold the Naches and Naches Drop Hydroelectric Plants to the United States Bureau of Reclamation. Water Rights
along with some buildings and equipment w~re turned over to the Bureau of Reclamation on March 10,2003. Access to the remainder
of the building and equipment was granted ru the United States Bureau of Reclamation effective January 1,2004. The third
amendment to the water rights purchase agreement was executed November 1, 2004. Transfer of the land rights per this agreement
occurred on March 31,2005. A letter to the FERC for ermission to clear FERC account 102 has been a roved.
Schedule Pa e: 410 Line No.21 Column:
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
I FERC FORM NO.1 (ED. 12-87) Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Oa, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
Franchises and Consents and are not re orted on this age. The net book value for relicensing at December 31, 2004 was $142,650.
Schedule Page: 410 Line No.22 Column: f
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents and are not reported on this page. The net book value for relicensing at December 31, 2004 was $3,468,380.
This cost of plant balance includes $4,576,357 of Powerdale asset retirement costs.
'Schedule Page: 410 Line No.23 Column: f
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents and are not reported on this page. The net book value for relicensing at Prospect unit numbers 1, 2, 3 & 4 on
December 31, 2004 was $137,304.
'Schedule Page: 410 Line No.24 Column: f
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents and are not reported on this page. The net book value for relicensing at Prospect unit numbers 1, 2, 3 & 4 on
December 31, 2004 was $137,304.
jSchedule Page: 410 Line No.25 Column: f
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents and are not reported on this page. The net book value for relicensing at Prospect unit numbers 1 , 2, 3 & 4 on
December 31, 2004 was $137,304.
'Schedule Page: 410 Line No.28 Column: f
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents and are not re orted on this a e. The net book value for relicensing at December 31, 2004 was $112 129.
Schedule Page: 410 Line No.29 Column:
Licensed Pro' ect No. 2381 a licable to both Ashton and St. Anthon lants.
Schedule Pa e: 410 Line No.33 Column: f
Costs reported for this plant do not include significant intangible costs due to relicensing which are recorded in FERC account 302
Franchises and Consents and are not re orted on this page. The net book value for relicensing at December 31, 2004 was $475,906.
Schedule Pa e: 410 Line No.35 Column:
Used in regulating the release of water from Klamath Lake and in maintaining proper water surface level in the Klamath River between
Klamath Falls and Keno, Ore on.
Schedule Pa e: 410 Line No.36 Column:
Storage reservoir for six plants on the Klamath River (Copco No.1, Copco No.2, East Side, West Side, John C. Boyle, and Iron
Gate).
ISchedule Page: 410 Line No.37 Column:
Common plant in North Umpqua Project. All common roads, employee houses, control equipment, etc. are in this account.
ISchedule Page: 410 Line No.37 Column: f
Costs reported for this plant do not include significant intangible costs due to relicensing and settlement which are recorded in FERC
account 302 Franchises and Consents and are not reported on this page. The net book value for relicensing and settlement on the
North Umpqua River system for the following projects at December 31, 2004 was $67,519,056: Lemolo 1 , Lemolo 2, Clearwater 1,
Clearwater 2, Toketee, Fish Creek, Soda Springs, Slide Creek and the North Umpqua Common Plant.
ISchedule Page: 410 Line No.43 Column:
Foote Creek Wind Farm is operated by Sea West Energy and is jointly owned. Costs reported for this plant represents the respondents
share. Ownership of the plant is as follows: PacifiCorp 78.79%, Eugene Water and Electric Board 21.21
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 422 Line No.Column:
The Alvey - Dixonville 500kV line is jointly owned by the respondent and the Bonneville Power Administration ("the BP A"
Ownership of the line is as follows: PacifiCorp 50.0%, the BPA 50.0%. Cost reported for this line reflects the respondents 50.
share. Operation and maintenance costs are shared between the two parties and responsibility is as follows: PacifiCorp 58.0% and the
BPA42.0%.
ISchedule Page: 422 Line No.Column:
The Dixonville - Meridian 500kV line is jointly owned by the respondent and the Bonneville Power Administration ("the BPA"
Ownership of the line is as follows: PacifiCorp 50.0%, the BP A 50.0%. Cost reported for this line reflects the respondents 50.
share. Operation and maintenance costs are shared between the two parties and responsibility is as follows: PacifiCorp 58.0% and the
BPA42.0%.
'Schedule Page: 422 Line No.26 Column: I
Costs are included in the Transmission Line listed above.
ISchedule Page: 422.Line No.: 10 Column: I
Costs are included in the Transmission Line listed below.
ISchedule Page: 422.Line No.19 Column: I
Costs are included in the Transmission Line listed above.
'Schedule Page: 422.Line No.28 Column: I
Costs are included in the Transmission Line listed below.
'Schedule Page: 422.Line No.26 Column: I
Costs are included in the Transmission Line listed above.
I FERC FORM NO.1 (ED. 12-87 Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmisslon 04/25/2005 2004104
FOOTNOTE DATA
'Schedule Page: 424 Line No.Column:
Cost of line is included in Transmission Line listed below.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 04/25/2005 2004104
FOOTNOTE DATA
ISchedule Page: 426.10 Line No.28 Column:
The Dixonville 500kV Substation is jointly owned by the respondent and the Bonneville Power Administration (lithe BP A"
Ownership of the substation is as follows: PacifiCorp 50.0%, the BP A 50.0%. Operation and maintenance costs are shared between
the two arties and res onsibilit is as follows: PacifiCo 58.0%, and the BP A 42.0%.
Schedule Pa e: 426.11 Line No.Column:
The Meridian 500kV Substation is jointly owned by the respondent and the Bonneville Power Administration (lithe BP A"
).
Ownership
of the substation is as follows: PacifiCorp 50.0%, the BP A 50.0%. Operation and maintenance costs are shared between the two
parties and responsibility is as follows: PacifiCorp 58.0%, and the BP A 42.0%.
IFERC FORM NO.1 (ED. 12-Page 450.
INDEX
Schedule Paae No.
Accrued and prepaid taxes
....,..................... .....................................
262-263
Accumulated Deferred Income Taxes
............ .,............ ........ ....................
234
272-277
Accumulated provisions for depreciation of
common utility plant
....... ........................................,....
utili ty plant
utility plant (summary)
Advances
from associated companies
... .. . .. . . . . .. . . . . . . . . . . . . . . . . . . .. .. ....... . .. . . . . . . . . . . . . . . . . . . . . . . . ......... . . . . . . . . .... . . . .,
356
219
200-201
. . . . . . .. . . . . . . .. . . . ............ ..... .. . . . . . . . . . . . . . . . .. ... . . . . . . . . . . . . . .. .. . .. .. ........ . . . . . . ... ... .
256-257
228-229Allowances
......... . . . . . . .. . .. . . .. . . . .. . ... .... "'" . . . .. .. . . . . . ... .... ..
Amortization
miscellaneous
Appropriations of Retained Earnings
. . . . . . . . . . . . . . .
Associated Companies
advances from ..................................................
corporations controlled by respondent
. . . . . . .
control over respondent
. . . . . . . . . . . . . . . .
interest on debt to
................ . . .... . . . . . . . . . . . . . . . ..... ....
...... 340
...........
202-203
118-119
. . . . . . . . . . . . .. . . ......... . . . . .. . .. . . . . . . . . . . . . . . . . . . ..
of nuclear fuel
. . . .. . . ... .. .. . ...... . . . . .. .. . . . . . . ... . . .. . ... . . . . . . . .... . . . .. . .... ..,. . . . .
256-257
103
. . . . . . ..
102
...........
256-257
. . . ......, ....... . . . . . . . . . . . . .. . . . . . . . . .... .. . . . . . . . . . . . .. . .. .. . .. .. . ..
Attestation
..... ..... . . . ................ . . . .... ... . . . . . . ... .. . .... .... . .... .. . . . ...
Balance sheet
comparative
notes
Bonds
.. ... .. . . .. .. . .. ...... ............. . . . . . . .. . . . ....... . . .. . .. .. . .. .
110-113
122-123
.................
256-257
. . . . ..
251
. . . . . . . . . . . . ..
254
252
251
252
120-121
.. . . . .. . .. . ..... ... ... . .. .. . ..... . . ... . . . .. . . ... ..... .. ... ..... . .. . ........ . . . . ..... "" ... ........ . . .. . . . . .. . .......... ...
Capi tal
expense
Stock
. . .. ...... . . .... .. ... ........ ..... .. ... . . . ... . . .. .... ......... .... . . ... . . .. . . ... .. ... . ... ....... . .. .. ... .. .. .. . .. . . . . . . .. .... . ..... ..
premiums
........ ...... ....... ".............
reacquired
......................................................'" ...,.................
subscribed
................. ...................................... .........
Cash flows, statement of
Changes
important during year
Cons truction
....... ... ... ...... . . . . . . . .. .. . .... .. ...... . . . . . . " . ........... ......... . .. . . . .. . . .. .. . .............. ... . . . . .. . . . '" . . . . . ... ..
108-109
work in progress
work in progress
common utility plant
- electric "
other utility departments
.... .. . .. ... ...... . . . . . . . . . .
work in progress
Control
. . . . . . . ... ..... . . . . . . . . .. . . .. . . . . . . . . . . . . . . ..
356
......... 216
200-201
. . . ..... ... ... ..... .... . . . . . . . . . . ...
corporations controlled by respondent
....... .................... ........,......
over respondent "
............... ........
Corporation
controlled by
..........
incorporated
. . . . . . . . . .
CPA, background information on
CPA Certification, this report
103
102
... . . . . . . . . . . . . . .. ... ... . . .. . .. . . . . .. . . . . . .... . . ....... . . .. .
103
101
101
... . . . . . . . . . . ..... .. .. . .. .. .. . . . . . . ... . ......... ... . . .. . .. . .. . .. . .. . . .. . .. . . .. . . . . . ... . . . . .. ..... .. ...
form
. . . .. . . . . ... .. .... .. .. . . . . . . . ...... . . . . . . .. . .. ...,... .. .
FERC FORM NO.(ED. 12-93)Index
INDEX (continued)
Schedule Paae No.
Deferred
credi ts,other
.. .. . . . . . . . . . . . . ... ... ..... . . ... . . . . . . . . . . . . . . . . . . ..........,...
269
233debi ts,miscellaneous
... . . ...... .. . .. . . . ... . . . . . . . . . . . . . . . . . . . ....... ......
income taxes accumulated - accelerated
amortization property .................................................... ................272-273
income taxes accumulated other property
................... .,.... .................
274-275
income taxes accumulated other
.................. ....,........... .........
276-277
income taxes accumulated pollution control facilities
................ . . . . . . . . . . . . . . . . . . . . ..
234
Definitions, this report fonn
............................... ....... ............
iii
Depreciation and amortization
of cornmon utility plant
. . . . . . . . . . . . .
of electric plant
............................... ..... . . . . . . .. . . . . . . .. .... .. ... ..
356
219
336-337
. . . . .. . . . . ..... ..
..... 105
256-257
354-355
118-119
118-119
401
..., ..... . . .. .. .. . . . .. . . . . .. . . . . . . ..... .. .. ......
Directors
.... ....,.. . . . . . . . .. . . . . . . . . . . . .. . . . . ........ . .. . . . . . .
Discount - premium on long-tenn debt "
...... ........
Distribution of salaries and wages
................ ......................................
Dividend appropriations
................. ................ ..........
Earnings, Retained
..,............. ...........................................................
Electric energy account
.. . . . . . . . . . .... . . .. . . . . . . ..... . . . . . . . .. .. . .. . . . . . . ........... .. .. ....
Expenses
electric operation and maintenance
electric operation and maintenance,
unamortized debt
..............
Extraordinary property losses
Filing requirements, this report fonn
General infonnation
............,............ .. . . . ... .... ... . . .... . .. ..............
320-323
. . . . . . . ... . . . . . . . . ..
323
256
. . . . . . . . . . . . . . . . . . . . . ..
230
.... . . ... ... ... . .. ....... .. .. . ... . . . . . . . . . . .
summary
........ . .... .... . . . . . . . .. . ...... . . . . ... .,..... . . . . .. . . . . ............ .......... . . . . . . . . .
101
Instructions for filing the FERC Fonn 1
Generating plant statistics
hydroelectric (large) ........,
...........,..........
pumped storage (large) ...,..............
......
small plants ................................................
steam-electric (large) ....,..................................
Hydro-electric generating plant statistics
...................
Identification
..............,......................... ......
Important changes during year
. . . ... .. ..,. .. . . . . . . . ... . . . . . . . . .. . . .. ......... . . ..
406-407
408-409
410-411
402-403
406-407
101
108-109
.. .. . ..... . .. . . . ...,......... . .. . . ..... ....... . . . . ... ....,... . .. .. . . . . ... . .. . . ... . .. . . ... ... . ... .. . ... . .. .. .. . .. . . .. ........ .. ..... . . .
Income
statement of, by departments
................. ........................ ......
114-117
statement of, for the year (see also revenues)
.......... ..................
114-117
deductions, miscellaneous amortization
................. . . . . . . . . . .. "
340
deductions, other income deduction
...... ...... ...... .............
340
deductions, other interest charges
...... ...... .,.... .......................
340
Incorporation infonnation
.................... .,..... ............... ........
101
FERC FORM NO.1 (ED. 12-95)Index
INDEX (continued)
Schedule Paae No.
Interest
charges,
Investments
paid on long-term debt,advances,etc
" . . . . . . . . . . . . . . . . . . . . . . . . . .. .. . . . .. ..,....
256-257
nonutilityproperty
.,................... .....,..... "
221
subsidiary companies "
.................. ....... .............
224-225
Investment tax credits, accumulated deferred
......,........ ..................................
266-267
Law, excerpts applicable to this report form "
....... .,.......
List of schedules, this report form
........................ .........
........ 2-
Long-term debt
................ ................................. .....................
256-257
Losses-Extraordinary property
....... ........ ...... .......................................
230
Materials and supplies
......,... ............................................... ..............
227
335Miscellaneous general expenses
.............. . . . . . . . . . .. . . . . . . . . . . . . . . . . . ... ... .. .. .... . . . ...
Notes
to balance sheet "
to statement of changes in financial position
.....................
to statement of income
to statement of retained earnings
'" ... .. .. . ... . ..
122-123
122-123
122-123
122-123
221
202-203
402-403
104
.. . ..... ..... .... . .. . . .. . . .. . .. .. .... .. . . .. . . . . . . . . . . . . .. . . . . . . ...... . .... . . . . . . .. . ... .. . . . . . . . . . . . . . . . . . . . . . . .. . . ... . .. . .. . . ..
Nonutility property
.............. ........................... ...... .......
Nuclear fuel materials
................................................. ......
Nuclear generating plant, statistics
Officers and officers I salaries
Operating
.... . . . . .. . .... . .. . . "" . .. . . . . ..... .,.. . . .. . . . . . . . . .. "" . . . . .... ..... ..... . . .. . . "
expenses-electric
expenses-electric
Other
( summary)
... .. .. . . . .. . . ..... .. .....,. ...... . . . . . . . ......
320-323
323
.................. .. . .. '" .. . ... . . . . ... " ............. .. "'" . . . . .
paid-in capital ................................
..................
donations received from stockholders
..................................
gains on resale or cancellation of reacquired
.. . . . .. . . ............
253
253
. . . .. .. . ..........
capi tal stock
" ...... ...... .. . . . . .. . . . . .. . . . . "'" . . . .. " . . . . . . . . . . .. "" ..
253
253
253
232
278
401
miscellaneous paid-in capital ................... "
reduction in par or stated value of capital stock
...........................................
regulatory assets "
'" ...................... ......................................
regulatory liabilities
.............. "'" "
Peaks, monthly, and output
............. ......................... .................
Plant, Common utility
accumulated provision for depreciation
................................ "
acquisition adjustments
............................................................
allocated to utility departments "
'" ......................................
completed construction not classified
............................................................
construction work in progress
. .. . . ....... . . . . ... .. .. . . . . ......... .. . .. . . . . . . .
356
356
356
356
356
356
356
356
356
expenses
......... ..... .. . . . . .. .. .. "" ..... ..... . . . . . .. . . .. .... .. . . . . ...
held for future use
in service
.. .. . . . .. . . .. . . . . . .. . . . .. . . .. . . . . . . ... . . ............. . . . . . . ., . . . .. . .. . .... .. ... "'" . . . . . . . . . . . . . . .. ... .. . . " " . .. . "'" .. ....... . .. . . . .... . .. . ...
leased to others "
........ "
plant data ......................................................"
. ... ...... . . . . .. .
336-337
401-429
FERC FORM NO.(ED. 12-95)Index
INDEX (continued)
Schedule Paae No.
Plant - electric
accumulated provision for depreciation
construction work in progress
. . . . . . . . . . . . . . . . .
held for future use ......................
in service
. . .. . .. ... .. .
219
216
214
204-207
213
. . . . .. . . . . . . . . . . . ....... .. ..... ...... . . . . .. . ... . . . . .. .. ....... .. . . .. . ... .. . . . . . ... . . . . . .. . ... . .. ... .. . . ...... .. . . . . . .. . . . ... . ....... .. . . . . . . . . .. . . . . .. . . . . .. ... . .. .... . .. . " .
leased to others
...... . . . . . . . .. .. . . . .. . . . . . . .. . .. . .. . .... ... . . .. ... ... ..
plant - utility and accumulated provisions for depreciation
amortization and depletion (summary) .............................................................
Pollution control facilities, accumulated deferred
201
234
Power Exchanges ........................................
......... ...... .........
326-327
Premium and discount on long-term debt
........ .............. ...... ................
256
Premium on capital stock ...............................................................,.. .......251
Prepaid taxes
............. ..................... .................................
262-263
Property - losses, extraordinary
........................ .................... .............
230
Pumped storage generating plant statistics ............................................... 408-409
Purchased power (including power exchanges)
........... .,............... ..................
326-327
Reacquired capital stock
....................... ...................... ............
250
Reacquired long-term debt ..........................
......
...,.. 256-257
.........
256-257
income taxes
... . ..... . . . . .. . . . . . . . .. . . . . . . .. .. . .. ...... ..... . .. . . . . . . . . . . . . .. . . . . .. ..
Receivers I certi ficates
... .. . . . ..... . .. . .. .. . . . .. "" .... . . . . . . . . . .
Reconciliation of reported net income with taxable income
from Federal income taxes "
Regulatory commission expenses deferred
Regulatory commission expenses for year
. . . . . . .
Research, development and demonstration acti vi ties
Retained Earnings
amortization reserve Federal
..... .. . . . . . . . . . . . .. ... . ... ......
261
233
350-351
352-353
. .. ... ..... . . .. . . . . . .. . ... .. . ....... ... . .. .. . . . . . . . ., . .. .... ..,.... .. .......... . .. . . .. '" ...... "
appropriated
.............,
statement of, for the year
unappropriated
. . . . . . . . . . .
Revenues - electric operating
. . . . . .... .......... . . . ............... .. ..
119
.........
118-119
...........
118-119
........
118-119
.........
300-301
. . . .. ...........,...... . . . . . ... .. . . . . . . ... .... . .. . . . .... ...... . . .... . ... . . . . .. . . .. . . ......... ... ..... ... ... ... ". . . .... . . . . ... ....,... .. ...... .. . .. . . ... .. . ... ...
Salaries and wages
directors fees
distribution of
officers
...... . . . .... . ....... ..... .. . .. . .......... ....... . . .. . ..... .. . .
105
.........
354-355
104
. . . . . . . . . . . . . . . ..
304
.............
310-311
.........
202-203
. . . . . . . . . . . .. 2-
. . . .. . . . . . .. ... ......... . . . . . . .. ... ........ ..... ... . .. . .. ... .. . . . . ...... .........,.. . . . " . . . .. . .. . ... .. . . ... ... .
Sales of electricity by rate schedules
...............,...... ...........
Sales - for resale
....,............ ................. ......
Salvage - nuclear fuel
........... ........................,....
Schedules, this report form
..................... ...... ......
Securi ties
exchange registration
.......... ..................... ............,.......... "
Statement of Cash Flows
..................,.... "..........,........
Statement of income for the year
.......... ......... ........... "
Statement of retained earnings for the year
...................... ............... ........
Steam-electric generating plant statistics
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Substations
............... .............. .......................... "
Supplies - materials and
................,... ........... ........ "
250-251
120-121
114-117
118-119
402-403
426
227
FERC FORM NO.1 (ED.12-90)Index
INDEX (continued)
Schedule Paae No.
Taxes
accrued and prepaid .........................................................................262-263
charged during year ........,................................................................262-263
on income, deferred and accumulated ....,........................................................234
272-277
reconciliation of net income with taxable income for ....................................,....... 261
Transformers, line - electric "
.................
429
Transmission
lines added during year .....................................................................424-425
lines statistics ............................................................................422-423
of electricity for others "
.............
328-330
of electricity by others ........................................................................332
Unamorti zed
debt discount ...............................................................................256-257
debt expense "
..........................
256-257
premium on debt .............................................................................256-257
Unrecovered Plant and Regulatory Study Costs
......................................................
230
FERC FORM NO.1 (ED. 12-90)Index