2005Annual Report Part I.pdf

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Pacific Power I Utah Power
Rocky Mountain Power
825 NE Multnomah
Portland, Oregon 97232
May 12, 2006
- ' ,---, " .: ,) ,:!
Idaho Public Utilities Commission
4 72 West Washington
Boise, ill 83702-5983
Attention:Jean D. Jewell
Commission Secretary
Re:FERC Form
Annual Report-Idaho Supplement to FERC Form 1
PacifiCorp (d.a. Utah Power & Light Company) hereby submits for filing an original and seven (7)
conformed copies of its 2005 FERC Form 1 and Annual Report - Supplement.
It is respectfully requested that all formal correspondence and Staff requests regarding this material be
addressed to:
Bye-mail (preferred):datarequest(fYpac ificorp. com
By regular mail:Data Request Response Center
PacifiCorp
825 NE Multnomah, Suite 300
Portland, Oregon, 97232
By fax:[phone]
Informal questions should be directed to Brian Dickman at [phone].
Sincerely,
:;P~'~lf,1\ ,
D. Douglas Larson
Vice President, Regulation
Enclosures
INSTRUCTIONS FOR FILING FERC FORMS 1, 1-F and 3-Q
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-a 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 Commissions 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
a 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-a electronically through the Form 1/3-a 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 ~tatistical 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.) Mall
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 110-113Statement of Income 114-117
Statement of Retained Eamings 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 accordina to the filina dates contained in section 18 CFR 141.1 ofthe Commission s reaulations. Submit Form 1-F according to the filing
dates contained in section 18 CFR 141.2 of the Commission s regulations. Submit Form 3-a 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 (a)).
. .
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-Q 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 Polnt-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 Reservations" 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 iii
EXCERPTS FROM THE LAW
Federal Power Act, 16 U.C. 791a-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 concerning the location, capacity, development -costs, and
relation to markets of power sites; ... to the extent 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...
GENERAL PENALTIES
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 $1 000 to be fixed by the
Commission after notice and opportunity for hearing .... "
FERC FORM NO.1 (ED. 12-91)Page iv
IDENTIFICATION
01 Exact Legal Name of Respondent 02 YearlPeriod of Report
PacifiCorp
-. .
End of 2005/04
03 Previous Name and Date of Change (if name changed during year)
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 06 Title of Contact Person
Henry Lay Corp Accounting Controller
07 Address of Contact Person (Street, City, State, Zip Code)
825 N.E. Multnomah, Suite 1900 Portland, OR 97232
08 Telephone of Contact Person,lncluding 09 This Report Is 10 Date of Report
Area Code (1) 00 An Original (2) 0 A Resubmission (Mo, Da, Yr)
[phone] 03/20/2006
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
Ve~~
04 Date Signed
Richard D. Peach
t---~ u (Mo, Da, Yr)
02 Title
Chief Financial Officer Richard D. Peach 03/20/2006
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:
REPORT OF MAJOR ELECTRIC UTILITIES LICENSEES AND OTHER
FERC FORM No.1/3-Q (REV. 02-04)Page 1
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/04(2) n A Resubmission 03/20/2006
LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms "none
" "
not applicable," or "" 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 Eamings 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)
. 13 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
Long-Term Debt 272-273
FERC FORM NO.1 (ED. 12-96)Page 2
Name of Respondent This 7!)ort Is:Date of Report Year/Period of Report
PaclfiCorp (1) An Origlna (Mo, Da, Yr)End of 2005/04
(2) Fi A Resubmission 03/20/2006
LI 5T OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none
" "
not applicable," or "" as appropriate, wh~re 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
Purchase and Sale of Ancillary Services 398
Monthly Transmission System Peak Load 400
Electric Energy Account 401
Monthly Peaks and Output 401
Steam Electric Generating Plant Statistics 402-403
Hydroelectric Generating Plant Statistics 406-407
Pumped Storage Generating Plant Statistics 408-409
Generating Plant Statistics Pages 410-411
Transmission Line Statistics Pages 422-423
Transmission Lines Added During the 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) IX! An Original(2) 0 A Resubmisslon
Date of Report
(Mo , Yr)
03/20/2006
Year/Period of Report
End of 2005/Q4
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. Multnomah, Suite 2000
Portland, OR 97232-4116
Corporate books are kept at:
825 N.E. Multnomah
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.
rncorporated 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,
Wyoming, Washington, rdaho 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) 0 Yes...Enter the date when such independent accountant was initially engaged:
(2) IX! No
FERC FORM No.1 (ED. 12-87)PAGE 101
Name of Respondent
PacifiCorp
This Report Is:
(1) IX! An Original(2) 0 A Resubmlssion
CONTROL OVER RESPONDENT
Date of Report
(Mo, Da, Yr)
03/20/2006
Year/Period of Report
End of 2005/Q4
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.
ScottishPower 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 (99.75% 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 2005/04
(2) (J A Resubmission 03/20/2006
RPORATIONS 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)r--
. "
X ""1"Mining 100r--
Energy West Mining Company Mining 100
Glenrock Coal Company Mining 100
Interwest Mining Company Mining 100
Pacific Minerals, Inc Mining 100
.Iilllr~66.
Environmental Services 89.
Rain Forest Carbon Credits 100
PacifiCorp Investment Management, Inc Management Services for PERCO 100
~.,..",
Mining 21.40
FERC FORM NO.1 (ED. 12-96)Page 103
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
ISchedu/e Page: 103 Line No.Column:
On Ma 4, 2000, the assets of Centralia Minin Co an were sold to TransAlta.
chedule Pa e: 103 Line No.Column:
Idaho Power holds a 33.34% ownershi interest in Brid er Coal Co
chedule Page: 103 Line No.Column:
CH2MHill holds a 10.10% owners ' interest in PacifiCo Environmental Remediation Co an.
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.
!Schedule Page: 103 Line No.10 Column:
The other joint owners of Trapper Mining, Inc. are Salt River Project (32.10%), Tri-State Generation and Transmission Association
Inc. (26.57%) and Platte River Power Authority (19.93%).
s interest is held throu Pacific Minerals, Inc.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo. Da, Yr)End of 2005/Q4
(2) Fi A Resubmission 03/20/2006
OFFICERS
1. 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.
2. 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 Iitie Name of Officer . ~~~ary
No.for Year(a)(b)(c)
President and Chief Executive Officer
Senior Vice President, General Counsel and Corporate Andrew P. Haller
Secretary
Executive Vice President and President of Utah Power
):'
Chief Financial Officer Richard D. Peach
Executive Vice President Matthew R. Wright
Executive Vice President Andrew N. MacRitchie
Senior Vice President Barry G. Cunningham
Senior Vice President
Senior Vice President Robert Klein
Senior Vice President
Senior Vice President Stan K. Watters
Vice President Donald D. Larson
Vice President Emest E. Wessman
Vice President & Treasurer Bruce N. Williams
FERC FORM NO.1 (ED. 12-96)Page 104
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmisslon 03/20/2006 2005/Q4
FOOTNOTE DATA
!Schedule Page: 104 Line No.Column: b
For additional information reguarding Ms. Johansen please refer to page 108 Important Changes During the Year Section 10, of this
Form 1.
!Schedule Page: 104 Line No.Column:
PacifiCorp sets forth the salary information for its five most highly compensated officers for the year ended December 31, 2005
consistent with Item 402 of Regulation S-K as promulgated by the Securities and Exchange Connmssion. 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
Schedule Pa e: 104 Line No.Column:
See footnote for a e 104 line 2, column C.
Schedule Pa e: 104 Line No.Column: b
A. Richard Walje is presently an elected Executive Vice President ofPacifiCorp and was appointed President of Utah Power effective
June 16, 2005.
!schedule Page: 104 Line No.Column:
See footnote for a e 104 line 2, column C.
chedule Pa e: 104 Line No.Column:
See footnote for pa e 104 line 2, column C.
chedule Pa e: 104 Line No.11 Column:
See footnote for a e 104 line 2, column C.
Schedule Page: 104 Line No.17 Column: b
Donald N. Furman resi ed as Senior Vice President of PacifiCo ,effective June 3, 2005.
chedule Pa e: 104 Line No.21 Column: b
Michael 1. Pittman resigned as a member of the Board of Directors and Senior Vice President ofPacifiCorp, effective September 7
2005. For additional information reguarding Mr. Pittman please refer to page 108 Important Changes During the Year Section 13, of
this Form 1.
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) EJA Resubmission 03/20/2006
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.
~g.
Name (an!1.lltle) or Director I"nnClpal tlUsmess Aooress(a)(b)
PacifiCorp Board of Directors:
iiLi:? ,1 Atlantic Quay
Glasgow, Scotland G2 8SP UK
825 NE Multnomah, Suite 2000
Portland, Oregon 97232
"'"
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
825 NE Multnomah, Suite 2000
Portland, Oregon 97232
201 South Main, Suite 2300
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
33m 1 Atlantic Quay - Robertson St.
Glasgow, Scotland G2 8SP UK
FERC FORM NO.1 (ED. 12-95)Page 105
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
!schedule Page: 105 Line No.Column:
For additional information reguarding Mr. Russell please refer to page 108 Important Changes During the Year Section 13, of this
Form 1.
!Schedu/e Page: 105 Line No.Column:
For additional information regarding Ms. Johansen please refer to Page 108 Important Changes During the Year Section 10, of this
Form 1.
ISchedule Page: 105 Line No.18 Column:
Michael 1. Pittman resigned as a member of the Board of Directors and Senior Vice President ofPacifiCorp, effective September 7
2005.
ISchedu/e Page: 105 Line No.21 Column:
A. Richard Walje is presently an elected Executive Vice President ofPacifiCorp and was appointed President of Utah Power effective
June 16 2005.
!Schedule Page: 105 Line No.33 Column:
Effective November 29, 2005, Stephen Dunn was elected to the Board of Directors ofPacifiCorp. For additional information please
refer to Page 108 Important Changes During the Year Section 13, of this Form 1.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
PacifiCorp
Date of Report
03/20/2006
Year/Period of Report
End of 2005/Q4
This Report Is:
(1) (29 An Original
(2) 0 A Resubmission
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 acquired 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 I (2) A Resubmission 03/20/2006 2005/Q4
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
ITEM 1.
State
California (a)
None
!!!!!ill (b)
Preston
Orel!on (c)
North Bend
Prineville
Wasco
Sweet Home
Lincoln City
Utah (b)
Apple Valley
Orangeville
Central Valley
Fairfield
Ivins
Scipio
Layton
Monticello
WashiDlrtoo (b)
Prescott
Sunnyside
WvomiOI!(d)
Douglas
Effective Date ExPiration Date Fee %
(Fee attached to franchise agreement)
08/18/2005 08/18/2030
02/01/2005 02/01/2015
OS/24/2005 OS/24/2010
07/20/2005 07/20/2010
09/12/2005 09/12/2015
09/27/2005 09/27/2015
03/30/2005 03/30/2015
04/27/2005 04/27/2025
06/08/2005 06/08/2025
06/29/2005 06/29/2025
08/16/2005 08/16/2015
09/20/2005 09/20/2025
10/12/2005 10/12/2010
10/21/2005 10/21/2025
10/14/2005 10/14/2025
11/07/2005 11/07/2015
07/11/2005 02/23/2015
(a) In the State ofCalifomia, franchise fees are an expense to PacifiCorp and are embedded in rates.
(b) In the States ofIdaho, Utah and Washington, franchise fees are an expense to PacifiCorp and are passed through to customers.
(c) In the State of Oregon, the first 3.5% of the franchise fees are an expense to PacifiCorp and are embedded in rates. Any amount
above the 3.5% is passed through to the customers within that municipality that the franchise agreement serves.
(d) In the State of Wyoming, the first 1.0% of the franchise fees are an expense to PacifiCorp and are embedded in rates. Any amount
above the 1.0% is passed through to the customers within that municipality that the franchise agreement serves.
ITEM 2.
None
ITEM 3.
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 5, 2004
with the proceeds, net book value, and selling costs transferred to account 102, Electric plant purchased or sold. Additional closing
IFERC FORM NO.1 (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 Resubmlssion 03/20/2006 2005/Q4
IMPORTANT CHANGES DURING THE QUARTERIYEAR (Continued)
costs were booked in December 2004 and cleared to account 102. A letter to the Federal Energy Regulatory Commission (the
FERC") for permission to clear account 102, Electric plant purchased or sold, was approved on May 10, 2005, Docket No.
AC05-43-000.
ITEM 4.
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 term which began 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 estimated
monthly charge includes reimbursement for the construction costs of the pipeline and facilities totaling $11.4 million and other
executory fees such as monthly operation and maintenance costs and property taxes. 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.
State regulatory commission authorization was not required.
ITEM 5.
Please refer to pages 424-425 of this Form 1 Transmission Lines Added During the Year.
ITEM 6.
For further discussion of other financing arrangements, see Notes to the Financial Statements Note 5 - Financing Arrangements
this Form 1. For further discussion of the proposed sale ofPacifiCorp, see Item 12 below.
Short-Term Debt
At March 16, 2006, PacifiCorp had $155.0 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. P AC-06-, Order No. 29999, dated March 14, 2006.
Securities and Exchange Commission, Release No. 35-27851 , dated May 28 2004 and filed with the FERC on February 6, 2006
pursuantto 18 CFR 366.6(b).
PacifiCorp s short-term borrowings and certain other financing arrangements are supported by an $800.0 million committed bank
revolving credit agreement which was amended and restated in August 2005. Changes included an increase to 65.0% in the covenant
not to exceed a specific debt-to-capitalization percentage, extension of the termination date to August 29 2010 and an exclusion of the
acquisition ofPacifiCorp by MidAmerican as an event of default under the agreement. The interest rate on advances under this facility
is generally based on the London Interbank Offered Rate (LIB OR) plus a margin that varies based on PacifiCorp s credit ratings. As of
March 16, 2006, this facility was fully available and there were no borrowings outstanding.
I FERC FORM NO.1 (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 Resubmisslon 03/20/2006 2005/Q4
IMPORTANT CHANGES DURING THE QUARTERIYEAR (Continued)
Long-Term Debt
For further discussion oflong-tenn debt, see Notes to the Financial Statements Note 6 - Long-Term Debt of this Fonn 1.
In June 2005, PacifiCorp issued $300.0 million of its 5.25% Series of First Mortgage Bonds due June 15 2035. PacifiCorp used the
proceeds for the reduction of short-tenn debt, including the short-tenn debt used in December 2004 to redeem its 8.625% Series of
First Mortgage Bonds due December 13, 2024 totaling $20.0 million. State Commission authorizations for this issuance were as
follows:
Oregon Public Utility Commission, Docket No. UF-4215, Order No. 05-258, dated May 9 2005.
Washington Utilities and Transportation Commission, Docket No. UE-050556, Order No. I, dated May II , 2005.
Idaho Public Utilities Commission, Case No. P AC-05-, Order No. 29787, dated May 17 2005.
Preferred Stock
On June 15 2005, PacifiCorp redeemed $7.5 million of its $7.48 No Par Serial Preferred Stock subject to the mandatory and optional
redemption terms for this series.
Common Stock
On December 30, 2005, PacifiCorp issued 11 627 907 shares of its common stock to its parent company, PacifiCorp Holdings
Inc.PIll"), at a total price oU125.0 million.
On September 30, 2005, PacifiCorp issued 11 617 101 shares of its common stock to Pill at a total price of$125.0 million.
On July 21 2005, PacifiCorp issued 11 737 090 shares of common stock to Pill in consideration of the capital contribution of$125.
million in cash made by Pill on June 30, 2005. State Commission authorizations for the issuances were as follows:
Oregon Public Utility Commission, Docket No. UF-4193 (1), Order No. 05-729, dated June 7 2005.
Washington Utilities and Transportation Commission, Docket No. UE-050555, Order No. I, dated May 11, 2005.
Idaho Public Utilities Commission, Case No. P AC-05-, Order No. 29786, dated May 17, 2005.
Other Financing Arrangements
For the year ending December 31 2005, PacifiCorp entered into three new standby letters of credit totaling $56.7 million at December
2005.
At December 31, 2005, PacifiCorp had $517.8 million of standby letters of credit and stand by bond purchase agreements 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 March 31, 2011. As of March 1 , 2006, PacifiCorp had amended all of these
bank arrangements to allow for the acquisition of PacifiCorp by MidAmerican.
PacifiCorp s revolving credit agreement contains customary covenants and default provisions. PacifiCorp monitors these covenants on
a regular basis to ensure that events of default will not occur, and as of December 31, 2005, PacifiCorp was in compliance with the
covenants of its revolving credit agreement. PacifiCorp s other fmancing arrangements generally contain similar covenants, although
the maximum permitted debt-to-capitalization ratio for some of the arrangements is 60.0%. PacifiCorp was also in compliance with
these agreements at December 31 2005. PacifiCorp anticipates seeking amendments to the covenants in these other fInancing
agreements to confonn them to the amended covenants in its revolving credit agreement.
I FERC FORM NO.1 (ED. 12-96)Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Me, Da, Yr)
PacifiCorp (2)A Resubmission 03/20/2006 2005/Q4
IMPORTANT CHANGES DURING THE QUARTERIYEAR (Continued)
ITEM 7.
None
ITEM 8.
The following table represents the estimated financial impact of the wage scale increases for the twelve months ended December 31
2005:
Unions Effective Estimated Annual
resented % Increase Date FinancialI act
IBEW 57 Generation 3.41%1/26/2005 & 7/26/2005 080,521
IBEW 57 Power Delivery 3.45%1/26/2005 281 187
IBEW 127 (WY) (b)8.46%3/26/2005 & 9/26/2005 924 532
UWUA 197 (Coos Bay, OR)3.45%1/26/2005 & 7/26/2005 127
IBEW 57 West Valley 1.80%5/26/2005 27~55
IBEW 57 (Laramie, WY)01%6/26/2005 9,472
IBEW 125 (W A & OR)28%1/26/2005 & 9/26/2005 010 942
IBEW 659 (OR & CA)58%1/26/2005 & 7/26/2005 959 412
Total 338 048
(a) This percentage increase represents the increase of wages for all effective dates during the
calendar year as compared to the wage scale of the prior effective period.
(b) Includes a 5.1 % retroactive pay adjustment that was due at contract ratification.
(c) Some amounts may be reimbursed by joint owners of steam generating facilities.
(d) The estimated annual impact is based on the time period :trom the effective date of the increase
to the end of the calendar year.
ITEM 9.
For a discussion of other legal proceedings not described in this item, see Notes to the Financial Statements Note 8 - Commitments
and Contingencies of this Form 1 , which is incorporated by reference herein.
INFORMATION REGARDING RECENT REGULATORY DEVELOPMENTS
Hydroelectric Relicensing and Decommissioning Actions
Several ofPacifiCorp s hydroelectric plants are in some stage of the relicensing or decommissioning process with the FERC. The
following summarizes the status of these projects.
Bear River hvdroelectric oro;ect - (Bear River, Utah and Idaho)
The license issued by the FERC that was final in May 2004 included a requirement to evaluate decommissioning the 7.5 MW Cove
Plant and associated project features (the "Cove Development"). In July 2005, a settlement agreement to remove the Cove
Development was signed by PacifiCorp, state and federal agencies, and non-governmental agencies. Decommissioning of the Cove
Development is contingent upon receiving an amended FERC license and removal order that is not materially inconsistent with the
settlement agreement and other regulatory approvals. The settlement agreement was filed with the FERC in August 2005 as part of an
application to amend the Bear River project license to provide for the removal of the Cove Development while continuing the
operation of the other Bear River project plants. Decommissioning of the Cove Development is expected to be completed by the end of
calendar 2006 for a total cost not to exceed $3.9 million, excluding inflation.
IFERC FORM NO.1 (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 03/20/2006 2005/Q4
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
Klamath hvdroelectric oro;ect - (Klamath River, Oregon and California)
In February 2004, PacifiCorp filed with the FERC a fmal application for a new license to operate the 161.4 MW Klamath hydroelectric
project. The FERC is scheduled to complete its required analysis by February 2007. PacifiCorp continues to participate in the
mediated settlement discussions with state and federal agencies, Native American tribes and other stakeholders in an effort to reach a
comprehensive agreement on project relicensing.
Condit hvdroelectric oroiect - (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 that is not materially inconsistent with the amended settlement agreement and other regulatory approvals. PacifiCorp is in the
process of acquiring all necessary permits in accordance with the terms and conditions of the amended settlement agreement.
Lewis River hvdroelectric oroiects - (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 Merwin, Swift No.1 and 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 July 2006.
Prosoect hvdroelectric oroiect - (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 before July 2006.
American Fork hvdroelectric oroiect - (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 $1.2 million, including process and
permitting costs (adjusted for inflation). The parties have agreed that project removal will begin in September 2006, subject to theFERC and other regulatory approvals.
Powerdale hvdroelectric oroiect - (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 cost $5.9 million (adjusted for inflation).
The plant will continue to operate until its removal, which is scheduled to commence in 2010.
State Regulatory Actions
PacifiCorp pursues a regulatory program in all states that it serves, with the objective of keeping rates closely aligned to ongoing costs.
The following discussion provides a state-by-state update, but does not address the possible effect of the proposed sale of
ScottishPowers indirect interest in PacifiCorp to MidAmerican. In each state, the sale of PacifiCorp will require regulatory notification
and/or approval. Although, PacifiCorp intends to pursue general rate increase requests as currently planned, management is unable to
predict the impact, if any, of the proposed sale and the process of obtaining such approvals on the pending matters described below.
IFERC 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)
PaclfiCorp (2) A Resubmission 03/20/2006 2005/04
IMPORTANT CHANGES DURING THE QUARTERIYEAR (Continued)
Utah
In March 2006, PacifiCorp filed a general rate case with the Utah Public Service Commission (the "UPSC") for an increase of$197
million annually, or an average increase of 17%, relating to continuing investments to serve Utah load and general inflation impacts.
In February 2005, the UPSC approved a stipulation settling the general rate case filed by PacifiCorp in August 2004. Under the
stipulation, PacifiCorp was awarded an increase in prices of $51.0 million annually, resulting in an average price increase of 4.7% and
an allowed return on equity of 10.5%. The stipulation also included an effective date of March I, 2005, which was a month earlier than
the April I , 2005 date required by Utah statute, resulting in a onetime benefit of $4.3 million of additional revenues.
In November 2005, PacifiCorp filed a Power Cost Adjustment Mechanism ("PCAM") application. The PCAM provides for 90.
recovery of actual power costs that exceed the amount in rates and a 100.0% refund of any over-collection of power costs.
approved, the PCAM will become effective after base rates are determined in PacifiCorp s next Utah general rate case.
Senate Bill 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. Senate Bill 26 also
establishes a voluntary process for utilities to obtain advance approval of certain other resource commitments and investment
decisions.
Oreeon
In February 2006, PacifiCorp filed a general rate case with the Oregon Public Utility Commission (the "OPUC") for an increase of
$112 million annually, or an average increase of 13., relating to cost increases in fuel, investments in generation, transmission and
distribution infrastructure, and general operating expenses.
In September 2005, Oregon s Governor signed into law Senate Bill 408. This legislation is intended to address differences between
income taxes collected by Oregon public utilities in retail rates and actual taxes paid by the utilities or consolidated groups in which
utilities are included for income tax reporting purposes. This legislation authorizes an automatic adjustment to rates based on the taxes
paid to governmental entities on or after January 1 2006. The OPUC adopted a temporary rule in September 2005 to establish filing
requirements for an annual tax report mandated by Senate Bill 408. The definitions adopted in the temporary rule would allocate a
share of individual taxable losses of affiliate companies to the utility even when the consolidated tax group pays more taxes than the
utility collects in retail rates. In October 2005, PacifiCorp filed a petition requesting the OPUC to repeal its temporary rule. PacifiCorp
is actively participating in the rulemaking process for adopting permanent rules required by Senate Bill 408. PacifiCorp expects that
the permanent rules will be issued during the fiscal quarter ending September 30, 2006.
In September 2005, the OPUC issued an order granting a general rate increase of$25.9 million, or an average increase of3.
effective October 2005. PacifiCorp filed its general rate case in November 2004, and following four partial stipulations with
participating parties, PacifiCorp s requested revenue requirement increase was $52.5 million. The OPUC's order reduced PacifiCorp
revenue requirement by $26.6 million based on the OPUC's interpretation of Senate Bill 408. In October 2005, PacifiCorp filed with
the OPUC a motion for reconsideration and rehearing of the rate order generally on the basis that the tax adjustment was not made in
compliance with applicable law. With the motion, PacifiCorp also filed a deferred accounting application with the OPUC to track
revenues related to the disallowed tax expenses. The OPUC granted PacifiCorp s motion for reconsideration and rehearing in
December 2005 and will reconsider whether Oregon Senate Bill 408 applies to the general rate case and, it if does, whether the tax
adjustment ordered by the OPUC results in rates that are unconstitutional. A hearing and submissions of written briefs are scheduled to
occur through May 2006.
In April 2006, long-term special contracts for PacifiCorp s Klamath basin irrigation customers will expire. Under the existing
contracts, customers receive power at rates equaling less than one-tenth ofPacifiCorp s average retail rates charged to other customers
on general irrigation tariffs. The rates that these Klamath basin customers will pay after the expiration of their special contract were a
contested issue in PacifiCorp s last general rate proceeding. The OPUC separated the rate-standard and rate-setting issues from the
general rate proceeding and required parties to file legal briefs on the appropriate rate standard to apply to these customers. In
November 2005, the OPUC issued an order stating that the same "just and reasonable" standard that applies to all ofPacifiCorp s retail
customers also applies to irrigation customers in the Klamath basin. A procedural schedule for the evidentiary rate-setting portion of
I FERC FORM NO.1 (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 1(2) . A Resubmission 03/20/2006 2005/Q4
IMPORTANT CHANGES DURING THE QUARTERIYEAR (Continued)
the proceeding has been established. An order is expected in April 2006. Legislation enacted in 2005 by the Oregon Legislative
Assembly and Governor Kulongoski limits increases in rates for the Klamath Basin customers to 50.0% per year. The legislation states
that the full cost of providing the rate credits will be spread among other PacifiCorp customers.
In February 2005, PacifiCorp filed an application for deferral of higher power costs in calendar 2005 due to continuing poor
hydroelectric conditions. PacifiCorp sought deferral of these costs to track for future recovery in rates. In May 2005, this deferral
application was suspended to allow parties to focus on the power cost adjustment mechanism filed by PacifiCorp in April 2005. If
approved, the proposed power cost adjustment mechanism will address recovery lag on Oregon s share of PacifiCorp s total net power
cost and the associated volatility resulting from such factors as hydroelectric, natural gas and load variability. The proposed power cost
adjustment mechanism is designed to be an enduring mechanism that more fairly balances risk between customers and shareholders.
Any approved power cost adjustment mechanism could result in the creation of related regulatory assets and liabilities that will capture
under- and over-recoveries, respectively. A full procedural schedule including testimony, a hearing, and legal briefs has been
completed and awaiting the Commission s order.
Wvomine
In February 2006, the Wyoming Public Service Commission ("the WPSC") orally approved an agreement settling the general rate case
filed by PacifiCorp in October 2005 and a separate December 2005 request by PacifiCorp to recover increased costs of net wholesale
purchased power used to serve Wyoming customers. The settlement provides for a $15.0 million revenue increase effective March 1
2006, an additional $10.0 million revenue increase effective July 1, 2006, a PCAM and an agreement by the parties to support a
forecast test year in the next general rate case application.
Washin1!ton
In May 2005 , PacifiCorp filed a general rate case request with the Washington Utilities and Transportation Commission (the
WUTC") for approximately $39.2 million. PacifiCorp filed rebuttal testimony in December 2005 that decreased the originally filed
amount by $6.6 million, for an updated request of $32.6 million. Hearings on the updated request took place in January and February
2006. If approved by the WUTC, customer rates would increase by 14.9% in April 2006. As part of that proceeding, PacifiCorp is also
requesting to recover $8.3 million in hydroelectric costs deferred through the period ending December 31 2005. PacifiCorp is
proposing that the rate treatment of the current low hydroelectric trend and power cost volatility be recovered following the general
rate case proceedings through a proposed PCAM.
Idaho
In July 2005 , the Idaho Public Utility Commission (the "IPUC") issued an order approving a settlement ofPacifiCorp s general rate
case filed in January 2005 and granting a stipulated rate increase of $5.75 million, or an average increase of 4.8%, effective September
2005. On that date, unrelated pre-existing surcharges expired, so the net effect to customers of the $5.75 million base increase was
an increase in rates of $2.1 million annually, or an average increase of 1.7%.
California
In November 2005, PacifiCorp filed a general rate case with the California Public Utilities Commission (the "CPUC") for an increase
of $11.0 million annually, or an average increase of 15.6% related to increasing costs, including power costs and operating expenses
as well as significant needed capital investments.
PacifiCorp s application also requests the implementation of an Energy Cost Adjustment Clause ("ECAC"), which would allow for
annual rate adjustments for changes in the level of net power costs, and a Post Test-Year Adjustment Mechanism ("PT AM"), which
would allow annual rate adjustments for changes in operating costs and plant additions. The proposed ECAC and PT AM would
operate outside the context of traditional general rate cases.
PacifiCorp also serves customers in California that fall under long-tenD special contracts for Klamath basin irrigation customers
described above. In January 2006, PacifiCorp served notice to the CPUC of its intent to reset the rates for these customers to standard
irrigation rates upon expiration of the special contracts in April 2006. After a formal protest by the irrigation customers, PacifiCorp
and the irrigation customers agreed upon and presented a joint proposal for a 4-year transition to standard irrigation rates to the CPUC
which is scheduled to rule on the proposal prior to the expiration of the special contracts.
IFERC FORM NO.1 (ED. 12-96)Page 109.
Name of Respondent This Report is:Date of Report YearlPeriod of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/04
IMPORTANT CHANGES DURING THE QUARTERIYEAR (Continued)
Multi-State Process
The Multi-State Process commenced in April 2002 and was a collaborative process with stakeholders from five of the six states
PacifiCorp serves. The project's focus was to design, develop and implement a cost allocation methodology that would achieve a more
pennanent consensus on each state s responsibility for the costs and benefits ofPacifiCorp s existing assets, enabling PacifiCorp to
recover the cost of future investments and providing 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 a cost
allocation methodology proposal, referred to as the "Protoco1." The Protocol was ftled with each of the state commissions in Utah,
Oregon, Wyoming and Idaho in September 2003. Following discussions with all parties, the proposal was further refined and
re-submitted to each of the state commissions as the "Revised Protoco1."
During June 2004 through November 2004, settlement discussions occurred in each of the above mentioned states, agreements were
reached with parties and hearings or oral arguments took place. Final ratification of the Revised Protocol was achieved in March 2005
and each of the state commissions in Utah, Oregon, Wyoming and Idaho issued orders approving and accepting the use of the Revised
Protocol cost allocation methodology for future rate setting in those states. The Revised Protocol cost allocation methodology forms
the basis of the Washington generaJ rate case ftled in May 2005 and the California general rate case ftled in November 2005. These
proceedings are ongoing, with Orders anticipated in 2006.
ITEM 10.
Related-Party Transactions
For further discussion of related party transactions, see Notes to the Financial Statements Note 4 - Related-Party Transactions of this
Form 1.
On May 16, 2005, the SEC approved PacifiCorp' s participation in a captive insurance program recently established by ScottisbPower
for its group companies. The captive insurance company, Dornoch International Insurance Limited ("DIn:'), is an indirect wholly
owned consolidated subsidiary of ScottisbPower. DIlL covers all or significant portions of the property damage and liability insurance
deductibles in many ofPacifiCorp s current policies, as well as activities that commercial insurance industry carriers will no longer
cover, such as overhead distribution and transmission line property damage. PacifiCorp has no equity interest in DIlL and has no
obligation to contribute equity or loan funds to DIlL. Premium amounts are established to cover loss claims, administrative expensesand appropriate reserves, but otherwise DIlL is not operated to generate profits.
According to the terms ofPacifiCorp s offer letter to its Senior Vice President, General Counsel and Corporate Secretary, Andrew
Haller, PacifiCorp made a $200 000 loan to Mr. Haller on May 21 , 2001 for the repayment of obligations to his former employer. At
December 31 2005, the outstanding loan balance was $54 394., including accrued interest. To repay the loan, Mr. Haller is required
to make two remaining annual payments of principal and interest (accruing the annual rate of 4.74%) in year 2006 and 2007.
Employment Agreements
On December 20 2005, PacifiCorp s President and Chief Executive Officer, Judith A. Johansen, signed an amendment to her existing
employment agreement with PacifiCorp and Scottish Power pIc ("ScottisbPower ), PacifiCorp s ultimate parent company. The
amendment:
states that Ms. Johansen will terminate her employment with PacifiCorp and resign as an officer and director ofPacifiCorp
and all affiliates, including ScottisbPower, effective immediately following the closing of the sale ofPacifiCorp to
MidAmerican Energy Holdings Company;
restates her waiver of participation in the PacifiCorp Executive Severance Plan;
provides for the cash retention award associated with PacifiCorp s sale to MidAmerican previously approved by
ScottisbPower s Remuneration Committee, as described below;
IFERC FORM NO.1 (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 I (2) A Resubmission 03/20/2006 2005/Q4
IMPORTANT CHANGES DURING THE QUARTERIYEAR (Continued)
modifies her Annual Incentive Plan ("AlP") tenDS consistent with recent changes to the AIP tenDS of other PacifiCorp named
executive officers, as described below;
clarifies the respective obligations ofPacifiCorp and ScottishPower to her after the termination of her employment;
provides that upon termination and assuming compliance by her with the tenDS of the Employment Agreement, she will
receive severance benefits equal to 12 months of salary, bonus and vehicle allowance, plus enhanced change in control
benefits under the PacifiCorp Supplemental Executive Retirement Plan;
provides for a gross-up payment by PacifiCorp to Ms. Johansen to cover any excise tax payable in connection with separation
payments, as well as certain health insurance and other benefits following her employment termination; and
adds certain customary obligations relating to non-disparagement and conflicts of interest.
On May 22 2005 the ScottishPower Remuneration Committee, in light of the expected timetable for obtaining regulatory approvals of
PacifiCorp s sale to MidAmerican, approved a cash retention award for PacifiCorp s Chief Executive Officer, Judith Johansen, equal
to one times base salary, which is contingent on the closing ofPacifiCorp s sale to MidAmerican and also on Ms. Johansens continued
employment and her satisfactory perfonnance of duties in the period through the sale s closing. Ms. Johansen will receive 80.0% of the
retention award upon the closing of the sale and the remaining 20.0% of the award 365 days from the date of the closing, provided
there have been no breach of warranty claims against ScottishPower or PHI under the Stock Purchase Agreement.
On October 4, 2005, PacifiCorp entered into a Compromise Agreement with its parent company, PHI, and its former Senior Vice
President and Director, Michael J. Pittman, that supersedes Mr. Pittman s employment agreement with PacifiCorp and ScottishPower
and documents the tenDS ofbis separation from the companies following a recent ScottishPower corporate restructuring that eliminated
his position. Under his employment agreement, Mr. Pittman was entitled to severance benefits equal to 12 months of salary, bonus and
vehicle allowance and 6 months of continued health insurance coverage. The Compromise Agreement supplements these benefits with
enhancements generally comparable to those payable under the PacifiCorp Executive Severance Plan for a termination following a
change in control of PacifiCorp, including an additional 12 months of salary, bonus and vehicle allowance and health insurance
coverage for an additional 18 months. ScottishPower has agreed to reimburse PacifiCorp for the cost of the supplemental benefits
provided by the Compromise Agreement.
On May 23, 2005, PacifiCorp s Compensation Committee approved a $6.0 million pool to be used for retention incentives during the
period prior to completion of the sale ofPacifiCorp to MidAmerican. PacifiCorp s Chief Executive Officer selected participants
consisting ofPacifiCorp senior management and other employees determined to be critical to PacifiCorp prior to completion of the
sale, and detennined the amounts and tenDS of retention awards, with Compensation Committee approval. Each participant was
required to sign a confidentiality and retention agreement. On August 29 2005, certain ofPacifiCorp s named executive officers
entered into agreements with ScottishPower for awards under the Transaction Incentive Program. The agreement signed by each
participating named executive officer has two principal components:
A modification of the executive officer s eligibility under PacifiCoro s Annual Incentive Plan ("AlP") for the fiscal vear
ending March 31. 2006. Participating executive officers have agreed that their AIP awards, as funded by PacifiCorp, will no
longer be based on multiple measurement criteria (some of which provided for a pro rata payout), but instead will be based on
a single measurement, PacifiCorp s perfonnance against its budget (which will not be subject to a pro rata payout). However
ScottishPower s Chief Executive Officer retains the discretion to approve or modify any AIP payout to these officers, subject
to review by ScottishPower s Remuneration Committee.
T enDS of Transaction Incentive Program A ward. Each participating executive officer is eligible for a transaction incentive
award in an amount equal to the executive officer s base salary (as adjusted for any existing retention agreement), payable as
follows:
1. 25% of the award was payable within one month of execution and delivery of the award agreement;
2. 50% of the award is payable three months after the closing ofPacifiCorp s sale to MidAmerican at $5.1 billion as set
IFERC FORM NO.1 (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 QUARTERlY EAR (Continued)
forth in the Stock Purchase Agreement governing the transaction, provided there are no claims by MidAmerican
against ScottisbPower; and
3. 25% of the award is payable 12 months after the closing, again as long as there are no claims by MidAmerican
against ScottisbPower.
Continued employment by PacifiCorp, observance of confidentiality obligations and satisfactory performance in support of
the transaction until the sale s completion are conditions to the executive officer s receipt of these payments. Ultimate
determinations of award eligibility will be made by ScottisbPower s Chief Executive Officer, subject to review by the
Remuneration Committee.
PacifiCorp and ScottisbPower also finalized the terms of Transaction Incentive Program awards to other participants. The terms and
conditions of these awards are generally similar to those of the named executive officer awards, but in some cases include satisfactory
achievement of specified employment objectives.
The summary of the Transaction Incentive Program award agreements for PacifiCorp named executive officers is qualified in its
entirety by reference to the terms of the fonn of such agreement, which is included as an exhibit hereto and incorporated by reference
herein.
Transaction Incentive
Program AwardName and Title
Andrew P. Haller
Senior Vice President, General Counsel and Corporate Secretary
Richard D. Peach
Chief Financial Officer
348,503
A. Richard Walje
Executive Vice President
250 000 (a)
330 811
305,292Matthew R. Wright
Executive Vice President
(a)Adjusted for existing retention agreement.
On May 26, 2005, PacifiCorp s Compensation Committee modified participation in PacifiCorp s Executive Severance Plan to provide
that certain members ofPacifiCorp senior management, including executive officers Andrew Haller, Andrew MacRitchie, Richard
Peach, Stan Watters and Matthew Wright, will be eligible for one times annual compensation general severance benefits and two times
annual compensation change-of-control severance benefits.
On May 2 2005, PacifiCorp s Chief Financial Officer, Richard D. Peach, entered into new compensation arrangements with
PacifiCorp and Scottish Power UK pIc ("SPUK"), an indirect wholly owned subsidiary of ScottisbPower, PacifiCorp s ultimate parent
company. Mr. Peach continues to report to PacifiCorp s Chief Executive Officer, Judith Johansen, but his current international
assignment to PacifiCorp from SPUK changed to permanent employment by PacifiCorp when he obtained U.S. permanent resident
status. Also effective May 1 2005, Mr. Peach's full international assignment benefits have ceased, but he will continue to receive
transition benefits, including foreign service premium payments, cost-of-living adjustment payments and housing and utilities
allowances for up to 18 months.
ITEM 11.
(Reserved)
ITEM 12.
For further discussion of important changes during the year, see page 122 Notes to the Financial Statements of this Fonn 1.
I FERC FORM NO.1 (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 Resubmisslon 03/20/2006 2005/Q4
IMPORTANT CHANGES DURING THE QUARTERIYEAR (Continued)
Sale of PacifiCorp
On May 23, 2005, ScottishPower and PHI, PacifiCorp s direct parent company, executed a Stock Purchase Agreement (the "Stock
Purchase Agreement") providing for the sale of all PacifiCorp common stock to MidAmerican for a value of approximately $9.4
billion, consisting of approximately $5.1 billion in cash plus approximately $4.3 billion in net debt and preferred stock, which will
remain outstanding at PacifiCorp. MidAmerican is based in Des Moines, Iowa, and is a privately owned global provider of energy
services. Through its energy-related business platfonns - CalEnergy, CE Electric UK, Kern River Gas Transmission Company,
Northern Natural Gas Company and MidAmerican Energy Company - MidAmerican provides electric and natural gas services to 5
million customers worldwide.
The closing of the sale ofPacifiCorp is subject to a number of conditions, including ScottishPower shareholder consent and regulatory
notification and/or approvals from the FERC, the Department of Justice or the Federal Trade Commission, the Federal
Communications Commission, the Nuclear Regulatory Commission and the public utility commissions in the states of Utah, Oregon
Wyoming, Washington, Idaho and California, as well as consents under existing third-party agreements. The Energy Policy Act of
2005 enacted in August 2005 includes a provision repealing the Public Utility Holding Company Act of 1935. The repeal took effect
on February 8 2006, prior to the closing of the sale ofPacifiCorp; as a result, approval of the transaction by the Securities and
Exchange Commission (the "SEC") is not required. ScottishPower shareholders approved the sale on July 22 2005. The Department
of Justice and the Federal Trade Commission completed their review ofMidAmerican s acquisition of-PacifiCorp in August 2005. The
FERC and the Nuclear Regulatory Commission fonnally approved MidAmerican s acquisition ofPacifiCorp in December 2005.
Pending satisfaction of the closing conditions, which is expected to occur prior to March 31, 2006, the Stock Purchase Agreement
requires ScottishPower to cause PacifiCorp to operate its business in the ordinary course consistent with past business practice. The
Stock Purchase Agreement also requires ScottishPower to obtain MidAmerican s prior approval to certain actions taken by PacifiCorp
beyond limits specified in the Stock Purchase Agreement, including:
borrowings or debt issuances;
capital expenditures;
construction or acquisition of new generation, transmission or delivery facilities or systems, other than as budgeted or
necessary to fulfill regulatory commitments (for example, the construction of the Currant Creek and Lake Side Power Plants is
permitted to proceed as planned);
unbudgeted significant acquisitions or dispositions;
modifications to material agreements with regulators;
issuance or sale of any capital stock to any person, other than PHI in certain circumstances;
adoption or amendment of employee benefit plans or material increases to employee compensation; and
payment of dividends to PHI.
Although PacifiCorp intends to, and the Stock Purchase Agreement requires ScottishPower to cause PacifiCorp to, operate its business
in the nonnal course pending the sale ofPacifiCorp to MidAmerican, some of the agreements and restrictions in the Stock Purchase
Agreement may affect how PacifiCorp manages its affairs.
While the sale ofPacifiCorp is pending and the Stock Purchase Agreement is in effect, ScottishPower and Pill have agreed to make
common equity contributions to PacifiCorp of$125.0 million at the end of each quarter in fiscal year 2006 and $131.25 million at the
end of each quarter in fiscal year 2007. If the sale is completed, MidAmerican will refund to PHI the amount of required fiscal year
2007 common equity contributions as an increase to the purchase price. On December 30, 2005, September 30, 2005 and June 30
2005, Pill made quarterly common equity contributions of$125.0 million as required by the Stock Purchase Agreement.
I FERC FORM NO.1 (ED. 12-96)Page 109.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PaclfiCorp (2) A Resubmission 03/20/2006 2005/04
IMPORTANT CHANGES DURING THE QUARTERNEAR (Continued)
Until completion of the sale (or tennination of the Stock Purchase Agreement), a joint executive committee with an equal number of
representatives from ScottishPower and MidAmerican is facilitating the transactions contemplated in the Stock Purchase Agreement
(including the process of obtaining required consents and approvals), integration planning and strategic development and will develop
recommendations concerning the structure and the general operation of PacifiCorp prior to the closing. If ScottishPower completes the
sale ofPacifiCorp, MidAmerican will cause the election of its own nominees as directors ofPacifiCorp and influence the management
and policies of PacifiCorp following the sale.
The Stock Purchase Agreement may be tenninated prior to completion by mutual agreement of MidAmerican and ScottishPower or
otherwise in specified circumstances, including (i) material breach of the representations, warranties or covenants of the parties and (ii)
the sale not being completed by May 23, 2006; however, if federal or state approvals have not been obtained but all other conditions
have been fulfilled or are capable of being fulfilled as of May 23 2006, either ScottishPower or MidAmerican may elect to extend the
term of the Stock Purchase Agreement until February 17, 2007.
In February and March 2006, the state commissions in all six states where PacifiCorp has retail customers approved PacifiCorp s sale
to MidAmerican. The approvals were conditioned on a number of regulatory commitments, including expected financial benefits in
the form of reduced corporate overhead and financing costs, certain mid- to long-term capital and other expenditures of significant
amounts and a commitment not to seek utility rate increases attributable solely to the change in ownership. The capital and other
expenditures proposed by MidAmerican and PacifiCorp include:
Approximately $812.0 million in investments (generally to be made over several years following the sale and subject to
subsequent regulatory review and approval) in emissions reduction technology for PacifiCorps existing coal plants, which,
when coupled with the use of reduced emissions technology for anticipated new coal-fueled generation, is expected to result
in significant reductions in emissions rates of sulfur dioxide, nitrogen oxide and mercury and to avoid an increase in the
carbon dioxide emissions rate; and
Approximately $519.5 million in investments (to be made over several years following the sale and subject to subsequent
regulatory review and approval) in PacifiCorp s transmission and distribution system that would enhance reliability, facilitate
the receipt of renewable resources and enable further system optimization.
PacifiCorp presently expects that annual capital expenditures of at least $1.0 billion will be required for at least the next five years
including the investments described above, and PacifiCorp expects to seek recovery of these costs in retail rates in the future. This
level of spending is dependent upon the availability of funding on reasonable tenns and conditions. If market conditions are not
favorable it may be necessary to postpone certain planned capital expenditures or take other actions.
The commitments approved by the state commissions also include credits that will reduce retail rates generally through 2010 to the
extent that PacifiCorp does not achieve identified cost reductions or demonstrate mitigation of certain risks to customers. The
maximum potential value of these rate credits to customers in all six states is $142.5 million. PacifiCorp and MidAmerican have made
an additional commitment to the state commissions that, following the sale and through December 31, 2008, PacifiCorp will not make
any dividends to MidAmerican or its affiliates that will reduce PacifiCorp s common equity capital below 48.25% ofPacifiCorp s total
capitalization without prior commission approval. After 2008, the required minimum level of common equity declines annually to
44.0% after December 31 2011.
Integrated Resource Plan
PacifiCorp filed its 2004 Integrated Resource Plan ("IRP") with the relevant state commissions in January 2005. PacifiCorp received
acknowledgement of the IRP in Washington, Idaho, and Oregon. In Utah, the IRP was acknowledged except for the Action Plan
component. The Action Plan will be considered as part of the Request for Proposal ("RFP") approval process under new state energy
resource procurement regulations. Oregon acknowledged the IRP with exceptions and new analytical requirements for PacifiCorp
next IRP. No action is required in Wyoming or California.
PacifiCorp released an update to the 2004 IRP in November 2005 that modified the type of future generation resources preferred by
PacifiCorp and defers the need for a significant new generation resource from 2009 to 2012.
IFERC FORM NO.1 (ED. 12-96)Page 109.
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(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/04
IMPORTANT CHANGES DURI NG THE QUARTERIYEAR (Continued)
Requests for Proposals
RFP 2003B - PacifiCorp s 2003 Integrated Resource Plan identified 1 400 MW of renewable resources as part ofa least-cost portfolio
of resources to meet PacifiCorp s growing demand over a lO-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 become available in
phases through calendar 2010. In May 2005, PacifiCorp entered into a 64.5 MW power purchase agreement in southeastern Idaho
which reached commercial operation in February 2006. In December 2005, PacifiCorp signed a 20 year Power Purchase Agreement
with AMP Resources for 42MW from Cove Fort. a geothennal project in Utah. PacifiCorp will issue an amendment to the 2003B RFP
in March 2006 to solicit new and existing updates for renewable proposals under the 2003B RFP for projects to be on line prior to
December 31 2007.
RFP 2012 (formerlv known as RFP 2009)- As a consequence of the update to the 2004 IRP, PacifiCorp has suspended the 2009
Request for Proposal ("RFP"). PacifiCorp will work with the state commissions and the independent evaluator required to participate
in the resource procurement process to identify the best way to procure the generation resource need identified for 2012. On January
, the Utah Commission issued a scheduling order (Docket 05-035-47) for the RFP 2012. Any revision to the procurement process
would remain subject to applicable commission acceptance.
Demand-side RFP - A demand-side management RFP covering all six states where PacifiCorp operates was issued in September 2005
requesting proposals for 80 MW or more of load-control resources and up to 1 752 000 MWh of conservation resources. The bids
were received in October 2005. Evaluations are expected to be completed by April 2006, at which time PacifiCorp will begin filing
tariffs with the state commissions. Tariff filings will continue after April 2006 until all new programs have been implemented.
Grid West and Regional Transmission Projects
In November 2005, the Bonneville Power Administration (the "BPA") withdrew future funding support for Grid West, a non-profit
corporation established by PacifiCorp and other western utilities as the platform for a proposed independent regional transmission
entity that would manage certain operational functions of the transmission grid and plan for necessary expansion. The BP A'
withdrawal resulted from the rejection by the Grid West interim board of directors' of certain terms BP A proposed as a condition of its
continued participation. In January 2006, British Columbia Transmission Corporation determined that it also would discontinue
funding Grid West due to uncertainties associated with BPA's withdrawal. In February 2006, Sierra Pacific Power Company
recommended to the Nevada Public Utilities Commission that they join WestConnect. The final decision will be based on the response
of the Nevada commission.
The remaining utilities (Avista Corporation, Idaho Power Company, NorthWestern Energy, PacifiCorp and Portland General Electric)
are reviewing the costs and impacts of moving forward.
PacifiCorp expects to continue its participation in support of the establishment ofa regional transmission entity, with the ultimate
decision to participate subject to a demonstration of net benefits to its customers.
Fair Value of Derivatives
Wholesale energy sales and purchase contracts are utilized primarily to balance PacifiCorp s physical excess or shortage of net
electricity for future time periods. When forward market prices are higher than contract prices, wholesale energy sales contracts will
have unrealized losses and wholesale purchase contracts will have unrealized gains. The opposite is true when forward market prices
are lower than contract prices. Umealized losses and gains will reverse in future periods when the contracts settle at contract prices and
do not result in cash collections or payments other than in meeting cash collateral requirements.
The following table shows the changes in the fair value of energy-related contracts subject to the requirements of SF AS No. 133
Accountingfor Derivative Instruments and Hedging Activities as amended, from December 31 , 2004 to December 31, 2005 and
quantifies the reasons for the changes.
IFERC FORM NO.1 (ED. 12-96) Page 109.
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(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03/20/2006 2005/Q4
IMPORTANT CHANGES DURING THE QUARTERIYEAR (Continued)
Fair value of contracts outstanding at December 31 , 2005
Regulatory
Net Net asset
Asset (Liability)(Liability) (c)
(271.3)277.
(34.35.
(52.52.
499.(458.
141.6 (92.
(M ilIions of dollars)
Fair value of contracts outstanding at December 31 , 2004
Contracts realized or otherwise settled during the period
Changes in fair values attributable to changes in
valuation techniques and assumptions (a)
Other changes in fair values (b)
(a)Effective March 31 2005, PacifiCorp adjusted its estimate of the period covered by market quotes from
three years to six years due to the increased availability of verifiable market quotations. This change had the
effect of decreasing the fair value of non-trading contracts by $52.7 million, offset by an increase in
regulatory net assets of the same amount.
Other changes in fair values include the effects of changes in market prices, inflation rates and interest rates
including those based on models, on new and existing contracts.
Net unrealized losses (gains) on contracts that have received regulatory approval for recovery in rates are
included as a regulatory net asset (liability).
(b)
(c)
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 upon market price quotations when available, and 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 six 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 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 six 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 evaluations and
refinements of model assumptions are performed on a periodic basis.
The following table shows summarized information with respect to valuation techniques and contractual maturities ofPacifiCorp
energy-related contracts qualifying as derivatives under SF AS No. 133 as of December 31 2005.
IFERC FORM NO.(ED. 12-96) Page 109.
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IMPORTANT CHANGES DURING THE QUARTERIYEAR (Continued)
Fair Value of Contracts at Period-End
Maturity Maturity
Less Than Maturity Maturity in Excess Total Fair
(Millions of dollars)1 Year 3 Years 5 Years of 5 Years Value
Trading:
Values based on quoted market prices ITom third-party sources (0.(0.
Values based on models and oth er valuation meth ods
Total trading (0.(0.
Non-trading:
Values based on quoted market prices ITom third-party sources 23.14.2.4 44.
Values based on models and oth er valuation meth ods 166.161.21.1 (250.97.
Total non-trading 170.$ 184.35.4 $ (248.141.8
Standardized derivative contracts that are valued using market quotations are classified as "values based on quoted market prices ITom
third-party sources." All remaining contracts, which include non-standard contracts and contracts for which market prices are not
routinely quoted, are classified as "values based on models and other valuation methods." Both classifications utilize market curves as
appropriate for the first six years.
ITEM 13.
For additional Officer and Director changes please refer to page 104 Officers and page 105 Directors of this Form 1.
On January 12, 2006, ScottishPower announced that Philip Bowman will succeed Ian Russell as ScottishPower s Group Chief
Executive effective January 16, 2006. As a result, Mr. Russell, who was Chairman ofPacifiCorp s Board of Directors, departed his
position as a director ofPacifiCorp effective January 16 2006.
On December 30 2005, PacifiCorp announced the appointment of Stephen Dunn to its Board of Directors and Compensation
Committee. Mr. Dunn is the Director of Human Resources and Communications for ScottishPower, PacifiCorp s ultimate parent
company. On November 29, 2005, PacifiCorp s Board of Directors elected Mr. Dunn to fill the vacancy created by the resignation
ITom that board ofScottishPower s previous Director of Human Resources.
On September 7, 2005, Group Director of Human Resources, Michael J. Pittman, resigned as an officer and director ofPacifiCorp.
ITEM 14.
IFERC FORM NO.1 (ED. 12-96) Page 109.
Name of Respondent This Report Is:Date of Report Year/Period of Report
PaclflCorp (1)An Original (Mo, Da, Yr)
(2)A Resubmission 03/20/2006 End of 2005/Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line Current Year Prior Year
Ref.End of QuarterlYear End BalanceNo.Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
UTILITY PLANT
Utility Plant (101-106, 114)200-201 532 898,825 871,234 077
Construction Work in Progress (107)200-201 594 604 038 439 891,117
TOTAL Utility Plant (Enter Total of lines 2 and 3)127 502 863 311 125 194
(Less) Accum. Provo for Depr. Amort. Depl. (108, 110, 111, 115)200-201 129,967 945 860,338 936
Net Utility Plant (Enter Total of line 4 less 5)997 534,918 450,786 258
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 (120.4)
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)997 534,918 8,450,786,258
Utility Plant Adjustments (116)122
Gas Stored Underground - Noncurrent (117)
OTHER PROPERTY AND INVESTMENTS
Nonutility Property (121)836 483 217 226
(Less) Accum. Provo for Depr. and Amort. (122)128,545 491,696
Investments in Associated Companies (123)16,579,182 15,111 724
Investment in Subsidiary Companies (123.224-225 84,853,402 69,298,918
(For Cost of Account 123., See Footnote Page 224, line 42)
Noncurrent Portion of Allowances 228-229
Other Investments (124)90,179 747 85,964,600
Sinking Funds (125)
Depreciation Fund (126)
Amortization Fund - Federal (127)
Other Special Funds (128)053,888 10,833,026
Special Funds (Non Major Only) (129)
Long-Term Portion of Derivative Assets (175)504,831 076 247 045,401
Long-Term Portion of Derivative Assets - Hedges (176)
TOTAL Other Property and Investments (Lines 18-21 and 23-31)714,205,233 435,979,199
CURRENT AND ACCRUED ASSETS
Cash and Working Funds (Non-major Only) (130)
Cash (131)694,774 336,089
Special Deposits (132-134)10,698,954 15,584,319
Working Fund (135)720 098
Temporary Cash Investments (136)113,778,292 854 734
Notes Receivable (141)028,037 425,229
Customer Accounts Receivable (142)259,768,410 290,118,180
Other Accounts Receivable (143)16,666,819 751 889
(Less) Accum. Provo for Uncollectible Acct.Credit (144)10,876 951 18,937 480
Notes Receivable from Associated Companies (145)
Accounts Receivable from Assoc. Companies (146)882,277 514 160
Fuel Stock (151)227 56,631,067 48,450 942
Fuel Stock Expenses Undistributed (152)227
Residuals (Elec) and Extracted Products (153)227
Plant Materials and Operating Supplies (154)227 117,959 772 105,246,617
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)IZI An Original (Mo, Da, Yr)
(2)A Resubmlssion 03/20/2006 End of 2005/Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)Continued)
Line Current Year Prior Year
Ref.End of QuarterlYear End BalanceNo.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)29,709,424
("(
Advances for Gas (166-167)
Interest and Dividends Receivable (171)987 58,070
Rents Receivable (172)571,410 441 927
Accrued Utility Revenues (173)169,648,000 158 191 000
Miscellaneous Current and Accrued Assets (174)151 667 282,313
Derivative Instrument Assets (175)884 958,679 367 444 527
(Less) Long-Term Portion of Derivative Instrument Assets (175)504 831 076 247 045,401
Derivative Instrument Assets - Hedges (176)
(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176
Total Current and Accrued Assets (Lines 34 through 66)168 538 262 833,023,058
DEFERRED DEBITS
Unamortized Debt Expenses (181)071 762 306 627
Extraordinary Property Losses (182.230
Unrecovered Plant and Regulatory Study Costs (182.230 839 912 16,818,879
Other Regulatory Assets (182.232 885 243,418 191 062,740
Prelim. Survey and Investigation Charges (Electric) (183)388 689 501,867
Preliminary Natural Gas Survey and Investigation Charges 183.
Other Preliminary Survey and Investigation Charges (183.
Clearing Accounts (184)10,469
Temporary Facilities (185)134,081 59,111
Miscellaneous Deferred Debits (186)233 65,950,331 78,628,533
Def. Losses from Disposition of Utility PIt. (187)
Research, Devel. and Demonstration Expend. (188)352-353
Unamortized Loss on Reaquired Debt (189)30,285,935 36,402 630
Accumulated Deferred Income Taxes (190)234 '~~~~;5~A"
,:.'
;'i1.::'7~j!J5~j"~'
Unrecovered Purchased Gas Costs (191)
Total Deferred Debits (lines 69 through 83)706,169,642 117,749 320
TOTAL ASSETS (lines 14-16, 32, 67, and 84)12,586,448,055 11,837 537 835
FERC FORM NO.1 (REV. 12"()3)Page 111
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
!Schedule Page: 110 Line No.57 Column:
Of the $71.9 million 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 co an of PacifiCo .
Schedule Pa e: 110 Line No.82 Column:
PacifiCorp keeps its accounting records on a fiscal-year basis for Securities Exchange Connnission (the "SEC") financial reporting
purposes. The fiscal year end is March 31st. 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 flIst
uarter FERC 3- flIst uarter of the calendar ear re ort than in subse uent uarters.
Schedule Pa e: 110 Line No.82 Column:
PacifiCorp keeps its accounting records on a fiscal-year basis for Securities Exchange Connnission (the "SEC") fmancial reporting
purposes. The fiscal year end is March 31st. 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 quarters.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 112)
Name of Respondent This Report is:Date of Report Year/Period of Report
PacifiCorp (1)IX)An Original (mo, , yr)
(2)A Rresubmission 03/20/2006 end of 2005/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Current Year Prior YearLineRef.End of QuarterlYear End Balance
No.Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
PROPRIETARY CAPITAL
Common Stock Issued (201)250-251 308,226,675 933,226,675
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)253 973,218 808
Installments Received on Capital Stock (212)252
(Less) Discount on Capital Stock (213)254
(Less) Capital Stock Expense (214)254 288,207 281 084
Retained Eamings (215, 215., 216)118-119 i492'558~7S 070,214,448
Unappropriated Undistributed Subsidiary Earnings (216.118-119 ;F'662,613,084
(Less) Reaquired Capital Stock (217)250-251
Noncorporate Proprietorship (Non-major only) (218)
Accumulated Other Comprehensive Income (219)122(a)(b)067 964 989,643
Total Proprietary Capital (lines 2 through 15)802,536 323 333 080,420
LONG-TERM DEBT
Bonds (221)256-257 007 276 242 880,571 649
(Less) Reaquired Bonds (222)256-257
Advances from Associated Companies (223)256-257
Other Long-Term Debt (224)256-257 45,000 000 500 000
Unamortized Premium on Long-Term Debt (225)46,435 154
(Less) Unamortized Discount on Long-Term Debt-Debit (226)397,420 989 338
Total Long-Term Debt (lines 18 through 23)046 925 257 928 131 465
OTHER NONCURRENT LIABILITIES
Obligations Under Capital Leases - Noncurrent (227)119,090 452,853
Accumulated Provision for Property Insurance (228.590,161 268 271
Accumulated Provision for Injuries and Damages (228.206 521 919,934
Accumulated Provision for Pensions and Benefits (228.432 165,438 382 512 888
Accumulated Miscellaneous Operating Provisions (228.929,426 585 027
Accumulated Provision for Rate Refunds (229)377 779
Long-Term Portion of Derivative Instrument Liabilities 533,082,317 552 527 026
Long-Term Portion of Derivative Instrument Liabilities - Hedges
Asset Retirement Obligations (230)62,393,140 66,683,967
Total Other Noncurrent Liabilities (lines 26 through 34)107,486,470 066 950,745
CURRENT AND ACCRUED LIABILITIES
Notes Payable (231)215,000 000 285,000,000
Accounts Payable (232)346,405 807 297 246 335
Notes Payable to Associated Companies (233)649 520 20,570,776
Accounts Payable to Associated Companies (234)599 395 16,726 512
Customer Deposits (235)35,286 140 581 709
Taxes Accrued (236)262-263 ~7,i~1P;4~9 604 016
Interest Accrued (237)036,300 552,956
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)IX)An Original (mo, , yr)
(2) 0 A Rresubmission 03/20/2006 end of 2005/04
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDIT~ntinued)
Line Current Year Prior Year
Ref.End of QuarterNear End BalanceNo.Title of Account Page No.Balance 12/31
(a)(b)(c)(d)
Matured Interest (240)
Tax Collections Payable (241)093 258 775 849
Miscellaneous Current and Accrued Liabilities (242)68,282 282 274,693
Obligations Under Capital Leases-Current (243)553,086 160 550
Derivative Instrument Liabilities (244)743 246,559 638 689,025
(Less) Long-Term Portion of Derivative Instrument Liabilities 533,082 317 552 527 026
Derivative Instrument liabilities - Hedges (245)
(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
Total Current and Accrued Liabilities (lines 37 through 53)979 901,466 898 176 342
DEFERRED CREDITS
Customer Advances for Construction (252)546 023 181,457
Accumulated Deferred Investment Tax Credits (255)266-267 608 060 528 180
Deferred Gains from Disposition of Utility Plant (256)
Other Deferred Credits (253)269 591 991 618,828
Other Regulatory Liabilities (254)278 198 320 601 128 575 966
Unamortized Gain on Reaqulred Debt (257)
Accum. Deferred Income Taxes-Accel. Amort.(281)272-277
Accum. Deferred Income Taxes-Other Property (282)
Accum. Deferred Income Taxes-Other (283)
Total Deferred Credits (lines 56 through 64)649 598 539 611 198 863
TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)586,448 055 837 537 835
FERC FORM NO.1 (rev. 12-03)Page 113
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
!schedule Page: 112 Line No.11 Column:
To ensure Account 216.1 only includes Unappropriated Undistributed Retained Earnings of existing subsidiaries, $669.4 million was
transferred from Account 216.1 to Account 216 following a review of 18 CFR 101.216 and 216.1. Although this transfer between
accounts has no impact on total retained earnings (the sum of Accounts 215 215.216 and 216.1), PacifiCorp has determined that a
transfer from Account 216.1 should be made when a subsidiary is transferred, sold, dissolved or liquidated, even in the absence of a
dividend or other fonna1 distribution. This approach is consistent with debits or credits made to Account 123.1 (Inves1ment in
Subsidiary Companies) when subsidiaries are transferred, sold, dissolved or liquidated.
The $669.4 million transferred to Account 216 primarily represents a debit balance in Account 216.1 associated with PacifiCorp
Group Holdings Company ("PGHC"), a former subsidiary ofPacifiCorp that was transferred to PacifiCorp s parent company,
PacifiCorp Holdings, Inc. ("PHI"), in 2002. Substantially all of the PGHC debit balance resulted from previous returns of capital from
PGHC to PacifiCorp that had been credited to Account 216 and debited to Account 216.1 by the amount of each distribution when
neither account should have been affected.
Only Accounts 216 and 216.1 were affected by the transfer, and total retained earnings was not affected. Furthermore, this transfer had
no effect on PacifiCorp s Statement of Income or Statement of Cash Flows and, except for the balances of Accounts 216 and 216.1
had no effect on the Comparative Balance Sheet or Statement of Retained Earnings. The following table represents account balances
for 2002, 2003 and 2004 as if Accounts 216.1 and 216 had reflected the transfer ofPGHC to PHI, compared to the actual as-reported
account balances in those years.
215.1 Appropriated Retained Earnings - Amortization Reserve Federal
216 Unappropriated Retained Earnings
216.1 Unappropriated Undistributed Subsidiary Earnings
Total Retained Earn ings
215.1 Appropriated Retained Earnings - Amortization Reserve Federal
216 Unappropriated Retained Earnings
216.1 Unappropriated Undistributed Subsidiary Earnings
Total Retained Earn ings
215.1 Appropriated Reta ined Earnings - Amortization Reserve Federal
216 Unappropriated Retained Earnings
216.1 Unappropriated Undistributed Subsidiary Earnings
Total Retained Earn ings
ISchedule Page: 112 Line No.12 Column:
See footnote on page 112, line 11 , column (c).
IFERC FORM NO.1 (ED. 12-S7)
As Reported Amended Variance
Twelve Months Twelve Months Twelve Months
Ended Ended Ended
December 31,December 31,December 31,
2002 2002 2002
575 811 575,811
936 324 910 266 356 556 (669,968 354)
(665 529,617)438 737 669 968 354
$ 274 371,104 $ 274 371,104
As Reported Amended Variance
Twelve Months Twelve Months Twelve Months
Ended Ended Ended
December 31 December 31 December 31,
2003 2003 2003
575 811 575,811
025,694 333 356,307,075 (669 387,258)
(664 367,224)020,034 669,387,258
$ 364,902 920 $ 364,902 920
As Reported Amended Variance
Twelve Months Twelve Months Twelve Months
Ended Ended Ended
December 31,December 31 December 31,
2004 2004 2004
575 811 575,811
066,638,637 397,251,379 (669,387 258)
(662,613,084)774,174 669,387 258
$ 407,601 364 $ 407,601,364
Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) X An Original (Mo, Da, Yr)
PacifiCorp (2) . A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) Fi A Resubmission 03/20/2006
STATEMENT OF INCOME
Quarterly
1. Enter in column (d) the balance for the reporting quarter and in column (e) the balance for the same three month period for the prior year.
2. Report in column (f) the quarter to date amounts for electric utility function; in column (h) the quarter to date amounts for gas utility, and in OJ the
quarter to date amounts for other utility function for the current year quarter.
3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in (k) the
quarter to date amounts for other utility function for the prior year quarter.
4. If additional columns are needed place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to
a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
8. Report data for lines 8, 10 and 11 for Natural Gas companies using accounts 404., 404., 404., 407.1 and 407.
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.QuarterlYear QuarterlYear No 4th Quarter No 4th Quarter
(a)(b)(c) (d) (e)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301
3 Operating Expenses
4 Operation Expenses (401)320-323 929,373,826 1,580 818,240
5 Maintenance Expenses (402)320-323 311,914 442 314,659,283
Depreciation Expense (403)336-337 372,668,587 360,452,077
Depreciation Expense for Asset Retirement Costs (403.336-337
..,
8 Amort. & Depl. of Utility Plant (404-405)336-337 48,011,207 52,530,998
9 Amort. of Utility Plant Acq. Adj. (406)336-337 479,353 5,479,353
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)256,147
Amort. of Conversion Expenses (407)
Regulatory Debits (407.307 820 961 370
(Less) Regulatory Credits (407.2,477
Taxes Other Than Income Taxes (408.262-263 96,297 630 915,793
Income Taxes - Federal (409.262-263 95,781,130 45,160,095
Other(409.262-263 878,018 12,313,742
Provision for Deferred Income Taxes (410.234, 272-277 690,441 169 715,726,978
(Less) Provision for Deferred Income Taxes-Cr. (411.234, 272-277 623,891 591 625,131,917
InvestmentTax Credit Adj. - Net(411.266 854 860 854,859
(Less) Gains from Disp. of Utility Plant(411.6)
Losses from Disp. of Utility Plant (411.7)60,094
(Less) Gains from Disposition of Allowances (411.8)16,224,770 908,181
Losses from Disposition of Allowances (411.
Accretion Expense (411.10)
." "
x",..
TOTAL Utility Operating Expenses (Enter Total oflines 4 thru 24)919,498,202 530,493,011
Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 519,453,886 459,091,928
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2005/Q4
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2). A Resubmission 03/20/2006
STATEMENT OF INCOME FOR THE YEAR (Continued)
9. Use page 122 for important notes regarding the statement of income for any account thereof.
10. Give concise explanations conceming unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected
the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights
of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations conceming significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accounts.
12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous years/quarter's figures are different from that reported in prior reports.
15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY
Current Year to Date Previous Year to Date(in dollars) (in dollars)
(g)
(h)
GAS UTILITY
Current Year to Date Previous Year to Date(in dollars) (in dollars)(i) Line
No.
094
16,224,770 908 181
48,011 207
5,479,353
256,147
530,998
5,479 353
307 820 961 370
2,477
915,793
160 095
313 742
781 130
878,018
854,859
919,498,202
519,453,886
530,493,011
459,091,928
FERC FORM NO.1 (ED. 12-96)Page 115
Name of Respondent This 7!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
STATEMENT OF INCOME FOR THE YEAR (continued)
Line TOTAL l;urrent3 Months Pnor 3 Months
No.Ended Ended
(Ref.Quarteriy Only Quarteriy Only
Title of Account Page No.Current Year Previous Year No 4th Quarter No 4th Quarter
(a)(b)(c)(d)(e)(f)
Net Utility Operating Income (Carried forward from page 114)519,453,886 459,091,928
Other Income and Deductions
Other Income
Nonutilty Operating Income
Revenues From Merchandising, Jobbing and Contract Work (415)532,054 462,283
(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)164,391 205,149
Revenues From Nonutility Operations (417)850,397 617 651
(Less) Expenses of Nonutility Operations (417.15,559 14,793
Nonoperating Rental Income (418)41,539 56,009
Equity in Earnings of Subsidiary Companies (418.119 839,244 813,948
Interest and Dividend Income (419)876,811 853,797
Allowance for Other Funds Used During Construction (419.915,057 163,409
Miscellaneous Nonoperating Income (421)396,466,451 88,025,572
Gain on Disposition of Property (421.142,752 929,669
TOTAL Other Income (Enter Total of lines 31 thru 40)417,484,355 105,702,396
Other Income Deductions
Loss on Disposition of Property (421.650,349 744,691
Miscellaneous Amortization (425)340 629,194 339,256
Donations (426.1) 340 948,545 854,177
Life Insurance (426.129,019 -8,495,975
Penalties (426.220,420 179,528
Exp. for Certain Civic, Political & Related Activities (426.031,555 717,717
Other Deductions (426.355,829,911 76,403,804
TOTAL Other Income Deductions (Total of lines 43 thru 49)357 180,955 73,743,198
Taxes Applic. to Other Income and Deductions
::~
Taxes Other Than Income Taxes (408.
Income Taxes-Federal (409.
Income Taxes-Other (409.262-263
" '",'
!m:..2,060;382:i;D:.H~\it;.
j;.
1;O6Z,891'
Provision for Deferred Inc. Taxes (410.234, 272-277
(Less) Provision for Deferred Income Taxes-Cr. (411.234, 272-277 .
,..
InvestmentTax Credit Adj.Net (411.
(Less) Investment Tax Credits (420)065,260 065,260
TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)20,951,662 346,756
Net Other Income and Deductions (Total of lines 41 50,59)39,351,738 26,612,442
Interest Charges
Interest on Long-Term Debt (427)237 603,134 229,563,697
Amort. of Debt Disc. and Expense (428)911,956 404,847
Amortization of Loss on Reaquired Debt (428.1) 116,695 291,370
(Less) Amort. of Premium on Debt-Credit (429)718 718
(Less) Amortization of Gain on Reaquired Debt-Credit (429.85,275 85,451
Interest on Debt to Assoc. Companies (430)340 473,493 426,708
Other Interest Expense (431)340 26,579,047 20,945,010
(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)16,966,931 6,767,217
Net Interest Charges (Total of lines 62 thru 69)257,629,401 255,776,246
Income Before Extraordinary Items (Total of lines 27, 60 and 70)301,176,223 229,928,124
Extraordinary Items
Extraordinary Income (434)
(Less) Extraordinary Deductions (435)
Net Extraordinary Items (Total of line 73 less line 74)
Income Taxes-Federal and Other (409.262-263
Extraordinary Items After Taxes (line 75 less line 76)
Net Income (Total of line 71 and 77)301 176,223 229,928,124
FERC FORM NO.1/3-Q (REV. 02-04)Page 117
Name of Respondent This-Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
ISchedule Page: 114 Line No.Column: h
In July 2003, the Emerging Issues Task Force ("EITF") issued EITF No. 03-11. Effective January 1, 2004, PacifiCOIp 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 PacifiCoII" 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 (fll'st
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-month 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 fll'st quarter of the calendar year (fourth quarter of the fiscal year). Adoption ofEITF 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
CY 03 CY 03 CY 03
$113,426 335 $ 82 874 255 $108 970 755
(110 706 073) (104 699 500) (90 471 134)
720 262) 21 825 245 (18 499 621)
Q4-FY 04
(OI-CY 04)
$98 740 774
(91 782 690)
958 084)
FY 2004 Total
$404 012 119
(397 659 397)
352 722)
Twelve Months Ended
December 312005 2004
Vehicle Depreciation $ 11 352 594 $ 10 640 857
!Schedule Page: 114 Line No.Column:
Per accounting orders in each of the six States ' that PacifiCorp operates in, PacifiCorp reclassifies the Depreciation expense of asset
retirement obli ations as either a re lato asset or liabili
Schedule Pa e: 114 Line No.14 Column:
Payroll taxes are charged to functional accounts, which is consistent with where labor is charged. The following table summarizes the
payroll tax expense that was charged to the functional accounts.
Twelve Months Ended
December 312005 2004
Payroll TaxExpense $ 35,422 794 $ 32 803 902
!Schedule Page: 114 Line No.17 Column: g
PacifiCorp keeps its accounting records on a fiscal-year basis for Securities Exchange Commission (the "SEC") fmancial reporting
purposes. The fiscal year end is March 31st. 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
IFERC FORM NO.1 (ED. 12-S7) 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 03/20/2006 2005/Q4
FOOTNOTE DATA
IFERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 118)
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
STATEMENT OF RETAINED EARNINGS
1. Do not report Lines 49-53 on the quarterly version.
Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
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.
If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Current Previous
QuarterlY ear QuarterlYear
Contra Primary Year to Date Year to Date
Line Item Account Affected Balance Balance
No.(a)(b)(c)(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period 066 638 637 025,694 333
2 Changes
3 Adjustments to Retained Eamings (Account 439)
9 TOTAL Credits to Retained Eamings (Acct. 439)
TOTAL Debits to Retained Eamings (Acct. 439)
Balance Transferred from Income (Account 433 less Account 418.300 336 979 228,114 174
Appropriations of Retained Eamings (Acct. 436)
TOTAL Appropriations of Retained Eamings (Acct. 436)
Dividends Declared-Preferred Stock (Account 437)iPs--"
238 083 790 083,789)
TOTAL Dividends Declared-Preferred Stock (Acct. 437)083 790 083,789)
Dividends Declared-Common Stock (Account 438)
Common Dividends 238 206,524 304 185,086,081)
TOTAL Dividends Declared-Common Stock (Acct. 438)206,524,304 185,086,081)
Transfers from Acct 216., Unapprop. Undistrib. Subsidiary Eamings ~llit,,:i ii;;~;~~1.4~-
Balance - End of Period (Total 1 15,16,22,29,36,37) fL;!;;;iP:,i:~~;~~IS,066,638,637
APPROPRIATED RETAINED EARNINGS (Account 215)
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 03/20/2006
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 2005/Q4
Line
No.
45 TOTAL Appropriated Retained Eamings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.
46 TOTAL Approp. Retained Eamings-Amort. Reserve, Federal (Acct. 215.
47 TOTAL Approp. Retained Eamings (Acct. 215, 215.1) (Total 45 46)
48 TOTAL Retained Eamings (Acct. 215, 215.1, 216) (Total 38, 47) (216.
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit)
50 Equity in Eamings for Year (Credit) (Account 418.
51 (Less) Dividends Received (Debit)
52 Transfer to Unappropriated Retained Eamings (Account 216)
53 Balance-End of Year (Total lines 49 thru 52)
Item
(a)
Current Previous
QuarterlY ear QuartertYear
Contra Primary Year to Date Year to Date
ccount Affected Balance Balance
(b)(c)(d)
( 662.613,084)
FERC FORM NO. 1/3-Q (REV. 02-04)Page 119
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PaclfiCorp 1(2)A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
IFERC FORM NO.1 (ED. 12-87) Page 450.
Blank Page
(Next Page is: 120)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
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)
Net Cash Flow from Operating Activities:
Net Income (Line 78(c) on page 117)301 176 223 229,928,123
Noncash Charges (Credits) to Income:
Depreciation and Depletion 384 308,603 368,502,039
",(",
683,721 68,756 548
; ,,"";-
Unrealized (Gains)/Losses on Derivative Contracts -42 795 968 178,421
Deferred Income Taxes (Net)929 034 88,888,432
Investment Tax Credit Adjustment (Net)920,120 920 120
Net (Increase) Decrease in Receivables 25,540 192 -47 265 983
Net (Increase) Decrease in Inventory 20,893 280 600,017
Net (Increase) Decrease in Allowances Inventory
Net Increase (Decrease) in Payables and Accrued Expenses 41,755 843 031 764
Net (Increase) Decrease in Other Regulatory Assets 82,487 911 139 090 761
Net Increase (Decrease) in Other Regulatory Liabilities 20,254 639 58,370,244
(Less) Allowance for Other Funds Used During Construction 915 057 163,409
(Less) Undistributed Eamings from Subsidiary Companies 839,244 820 142
::;-
529,623 703,275
~tf~j)ij~~~Jj~,jtp\p\lI~~' d~~ ~~ji)6~):; G: i:,
c",,"","747 688 -47 543,663
"'-'
,. 'i//
Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)901 540 530 718 272 677
Cash Flows from Investment Activities:
Construction and Acquisition of Plant (including land):
Gross Additions to Utility Plant (less nuclear fuel)974 531 524 739,978,745
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)974 531 524 739,978 745
Acquisition of Other Noncurrent Assets (d)
Proceeds from Disposal of Noncurrent Assets (d)651,413 969,744
Investments in and Advances to Assoc. and Subsidiary Companies 682,333 568 178
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 ~ort Is:Date of R~ort Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, r)End of 2005/04
(2) Ei A Resubmisslon 03/20/2006
STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Proceeds or Payrnents;(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.QuarterlYear 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
::'
:,.:"r
.,.
10,196 012 374 268
Net Cash Provided by (Used in) Investing Activities
Total of lines 34 thru 55)981,758,456 755,951,447
Cash Flows from Financing Activities:
Proceeds from Issuance of:
Long-Term Debt (b)295,914 826 394 982 159
Preferred Stock
Common Stock 374 992,877
:..
883,910
Net Increase in Short-Term Debt (c)846,025
Other (provide details in footnote):
Cash Provided by Outside Sources (Total 61 thru 69)670 907 703 455,712,094
Payments for Retirement of:
Long-term Debt (b)173,234 000 283,975,000
Preferred Stock 500 000 500 000
Common Stock
",,
877 300
Net Decrease in Short-Term Debt (c)102 322
Dividends on Preferred Stock 083 790 083 790
Dividends on Common Stock 206,524,304 -185,086,081
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)112 368 061 611 547
Cash and Cash Equivalents at Beginning of Period 19,108 725 79,720,272
Cash and Cash Equivalents at End of period 131,476,786 19,108,725
FERC FORM NO.1 (ED. 12-96)Page 121
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
Line No.Column: ISchedule Page: 120 YTD
Dec. 31 2005$ 48 011,207
5,479,353
563,967
629,194
683,721
Amortization of Software and Other Intangibles
Amortization of Electric Plant Acq. Adj. - Common
Amortization of Regulatory AssetslLiabilities
Amortization of Hydro Relicensing
YTD
Dec. 31,2004
$ 52,530,998
5,479,353
746,197
68,756,548
FERC
Account
404
406
407/407.3/407.4
425
ISchedule Page: 120 Line No.Column:
Accounts Receivable from Associated Companies
Tax Receivable from Associated Companies (PHI)
Accounts Payable To Associated Companies
Tax Payable To Associated Companies (pHI)
YTD
Dec. 31, 2005$ 2,612,408
948,541
(7,171,073)
(4,860,253)
529 623
YTD
Dec. 31,2004
$ (31,727)
(41 948 541)
047,719
16,229,274
$ (21 703,275)
FERC
Account
146/171
165
234/237
236
!schedule Page: 120' Line No.Column:
Coal Depreciation & Depletion included in Cost of Fuel
PMl Equity Earnings included in the Cost of Fuel
(Gain)lLoss on Sale of Property
Accumulated Provision for Pension & Benefits
Share Based Compensation Expense
Write-Off of Assets Under Construction
Accumulated Provision for MininglEnvironlDecom
Other
YTD
Dec. 31,2005
$ 12 354,940
(14 715,240)
364 968)
696,634
973,218
227 101
409,456
166,547
747,688
YTD
Dec. 31, 2004
$ 11,069,299
(17,290,644)
(2,637,454)
(29,325 548)
315,275
(14,584,594)
910 003
(47 543,663)
FERC
Account
151
501
254/411.6/411.7
228.
211
107
228/253
Various
ISchedule Page: 120 Line No.Column:
Other Investments/Special Funds
Restricted Cash
Other
YTD
Dec. 31,2005$ (5,397,030)
(4,724 011)
(74,971)
(10,196,012)
YTD
Dec. 31, 2004$ (4 842,306)
531 962)
(13,374,268)
FERC
Account
124/128
128/134
Various
!schedule Page: 120 Line No.Column:
Subsidiary Borrowing (Note Agreements)
YTD
Dec. 31,2005
YTD
Dec. 31,2004$ 883,910
FERC
Account
!schedule Page: 120 Column:
233
Line No.
Subsidiary Borrowing (Note Agreements)
YTD
Dec. 31,2005
$ (18,877 300)
YTD
Dec. 31 , 2004
FERC
Account
233
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
PacifiCorp
Date of Report
03/20/2006
Year/Period of Report
End of 2005/Q4
This Report Is:
(1) 129 An Original
(2) 0 A Resubmission
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of I ncome 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 3Q 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 3Q 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 REQUIRED 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 Resubmlssion 03/20/2006 2005/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
PacifiCorp
(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 ("the
FERC") as set forth in its applicable Uniform 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 Securities and Exchange Commission (the "SEC") Annual Report on Form 10-K as of, and for the year ended, March
, 2005 for financial statements and complete footnotes prepared in accordance with accounting principles generally accepted in the
United States of America ("GAAP"). PacifiCorp has a fiscal year end as of March 31.
The following are some of the significant differences between FERC reporting standards and GAAP:
Investments in Subsidiaries
Under FERC reporting standards, 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.5 J. 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 SFAS No. 143 Accountingfor 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 SF AS No.1 09 Accounting
for Income Taxes. All such amounts are classified as gross non-current assets and gross non-current liabilities for FERC.
Unrealized 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. Umealized gains on wholesale sales, purchased power and fuel are reported in Other Income and unrealized
losses on wholesale sales, purchased power and fuel are reported in Other Income and Deductions. For GAAP reporting purposes
unrealized gains and losses on wholesale sales are reported in Revenues and unrealized gains and losses on purchased power and
fuel are reported in Energy Costs.
Reclassifications
Certain reclassifications of balance sheet and income statement amounts have been made to assist in multi-jurisdictional
rate making 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, 2005 in the
supplemental FERC filing, except in relation to new accounting standards.
These notes to the fmancial statements for the twelve months ended December 31 , 2005 and 2004 are presented in accordance with
IFERC FORM NO.1 (ED. 12-SS) 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 03/20/2006 2005/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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
Companys SEC reporting fiscal year ended March 31 , 2005.
Sale of PacifiCorp
On May 23, 2005, ScottishPower and PacifiCorp Holdings, Inc. ("PHI"), PacifiCorp s direct parent company, executed a Stock
Purchase Agreement (the "Stock Purchase Agreement") providing for the sale of all PacifiCorp common stock to MidAmerican
Energy Holdings Company ("MidAmerican ) for a value of approximately $9.4 billion, consisting of approximately $5.1 billion in
cash plus approximately $4.3 billion in net debt and prefen-ed stock, which will remain outstanding at PacifiCorp. MidAmerican is
based in Des Moines, Iowa, and is a privately owned global provider of energy services.
The closing of the sale ofPacifiCorp is subject to a number of conditions, including ScottishPower shareholder consent and regulatory
notification and/or approvals from the Federal Energy Regulatory Conunission (the "FERC"), the Department of Justice or the Federal
Trade Commission, the Federal Communications Commission, the Nuclear Regulatory Commission and the public utility conunissions
in the states of Utah, Oregon, Wyoming, Washington, Idaho and California, as well as consents under existing third-party agreements.
Pending satisfaction of the closing conditions, the Stock Purchase Agreement requires ScottishPower and PHI to cause PacifiCorp to
operate its business in the ordinary course consistent with past business practice. The Stock Purchase Agreement also requires
ScottishPower and PHI to obtain MidAmerican s prior approval to certain actions taken by PacifiCorp beyond limits specified in the
Stock Purchase Agreement, including:
bon-owings or debt issuances;
capital expenditures;
construction or acquisition of new generation, transmission or delivery facilities or systems, other than as budgeted or
necessary to fulfill regulatory commitments;
unbudgeted significant acquisitions or dispositions;
modifications to material agreements with regulators;
issuance or sale of any capital stock to any person, other than PHI in certain circwnstances;
adoption or amendment of employee benefit plans or material increases to employee compensation; and
payment of dividends to PHI.
While the sale ofPacifiCorp is pending and the Stock Purchase Agreement is in effect, ScottishPower and PHI have agreed to make
common equity contributions to PacifiCorp of $125.0 million at the end of each quarter in fiscal year 2006 and $131.25 million at the
end of each quarter in fiscal year 2007. If the sale is completed, MidAmerican will refund to PHI the amount of required fiscal year
2007 common equity contributions as an increase to the purchase price. As described in Note 7 - Common Shareholder s Equity, PHI
has made the equity contributions required to date by the Stock Purchase Agreement.
Pursuant to the Stock Purchase Agreement, ScottishPower has agreed to cause PacifiCorp to not pay quarterly dividends to PHI in
excess of$214.8 million in the aggregate during fiscal year 2006 and $242.3 million in the aggregate during fiscal year 2007. These
restrictions will terminate upon either the close of the sale ofPacifiCorp or the earlier termination of the Stock Purchase Agreement.
PacifiCorp is party to pre-existing agreements with affiliates of MidAmerican for certain gas transportation and steam purchase
transactions. These transactions are not significant to PacifiCorp s Energy costs.
Pursuant to the Stock Purchase Agreement, upon the closing ofPacifiCorp s sale to MidAmerican, PacifiCorp will settle outstanding
intercompany liabilities with ScottishPower subsidiaries and transfer to certain of these affiliate entities the assets and liabilities
associated with the participation of affiliate employees in benefit plans sponsored by PacifiCorp.
Cash and Cash Equivalents
For the purposes of these financial statements, PacifiCorp considers all liquid investments with maturities of three months or less, at
the time of acquisition, to be cash equivalents. The following table is a reconciliation of the cash accounts on the Balance sheets to the
Statement of cash flows:
IFERC FORM NO.1 (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 03/20/2006 2005/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
December 31 December 31
2005 2004
17.9.3
(0.
113.
131.5 19.
(Millions ofdollars)
Cash (131)
Working Funds (135)
Temporary Cash Investments (136)
Total cash and cash equivalents
Stock-Based Compensation
As permitted by Statements of Financial Accounting Standards ("SFAS") No. 123 Accountingfor Stock-Based Compensation SFAS
No. 123"), PacifiCorp accounts for its stock-based compensation arrangements, primarily employee stock options, under the intrinsic
value recognition and measurement principles of Accounting Principles Board ("APB") Opinion No. 25 Accounting for Stock Issued
to Employees APB No. 25"), and related interpretations in accounting for employee stock options issued to PacifiCorp employees.
Under APB No. 25, because the exercise price of employee stock options equals the market price of the underlying stock on the date of
grant, no compensation expense is recorded if the ultimate number of shares to be awarded is known at the date of the grant. All
options are issued in ScottishPower American Depository Shares. Had PacifiCorp determined compensation cost based on the fair
value at the grant date for all stock options vesting in each period under SFAS No. 123, PacifiCorp s net income would have been
reduced to the pro fonna amounts below:
Pro fonna net income
Twelve Twelve
Months Months
Ended Ended
December 31 December 31
2005 2004
301.2 229.
2.5
(3.(1.9)
300,228.
(Millions of dollars)
Net income as reported
Add: stock-based compensation expense using the
intrinsic value method, net of related tax effects
Less: stock-based compensation expense
using the fair value method, net of related tax effects
New Accounting Standards
FSP SFAS No. 106-
In May 2004, the Financial Accounting Standards Board (the "FASB") released FASB Staff Position ("FSP") SFAS No. 106-
Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003
FSP SF AS No.1 06-). FSP SF AS No.1 06-2 provides guidance on the accounting for the effects of the Medicare Prescription Drug
Improvement and Modernization Act of 2003 (the "Medicare Act"). The Medicare Act introduced a prescription drug benefit under
Medicare, as well as a federal subsidy to sponsors of retiree health care plans that include prescription drug benefits. Employers that
sponsor postretirement health care plans that offer prescription drug benefits must determine if their prescription drug benefits are
actuarial1y equivalent to the drug benefit provided under Medicare Part D as of the date of enactment of the Medicare Act to be
entitled to receive the subsidy. PacifiCorp determined that its prescription drug plan met the actuarial equivalence requirements and
therefore calendar year 2004 results reflect such.
Subsequent to initial adoption, the Centers for Medicare and Medicaid Services released fmal regulations for implementing the
Medicare Act. These regulations were issued on January 21 2005, and provide guidance for making a determination of whether the
benefits under a lan will meet the definition of actuarial e uivalence. PacifiCo ex ects these re ations to result in an additional
FERC FORM NO.1 ED.12-88 Page 123.
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NOTES TO FINANCIAL STATEMENTS (Continued)
decrease in the accumulated postretirement benefit obligation of approximately $18.0 million and an additional decrease in the annual
net periodic postretirement benefit cost of approximately $2.5 million during the calendar year ending December 31, 2005.
SF AS No. 123R and SAB No. 107
In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment SFAS No. 123R"), a revision of the originally issued
SF AS No. 123. SF AS No. l23R establishes standards for the accounting for transactions in which an entity exchanges its equity
instruments for goods or services. In March 2005, the SEC issued Staff Accounting Bulletin C'SAB") No.1 07 ("SAB No. lOT'
which provides additional guidance in applying the provisions of SF AS No. 123R. SF AS No. 123R requires that the cost resulting
from all share-based payment transactions be recognized in the fmancial statements using the fair value method. The intrinsic value
method of accounting established by APB No. 25 will no longer be allowed. SAB No. 107 describes the SEC Staff's guidance in
detennining the assumptions that underlie the fair value estimates and discusses the interaction of SF AS No. 123R with other existing
SEC guidance.
In April 2005, the effective date of SF AS No. 123R was defelTed 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 for awards modified
repurchased or cancelled after the required effective date. The provisions of SAB No.1 07 will be applied upon adoption of SF AS No.
123R.
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 SF AS No. 123R.
FSP SF AS No. 109-
In December 2004; the FASB issued FASB Staff Position ("FSP") SFAS No. 109-Application of FASB Statement No. JO9
Accountingfor Income Taxes, to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of
2004. The tax deduction addressed inFSP SF AS No. 109-1 will be treated as a "special deduction" as descnbed in SFAS No. 109
Accountingfor 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. PacifiCorp
currently believes the effect of this statement on its financial position and results of operations is immaterial.
FIN
In March 2005, the FASB issued FASB Interpretation No. 47 Accountingfor Conditional Asset Retirement Obligations
Interpretation of FASB Statement No. 143 ("FIN 47"). FIN 47 clarifies that the term "conditional asset retirement obligation" as used
in SF AS 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. FIN 47 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 at the end of the fiscal year ending after December 15, 2005. PacifiCorp is currently
evaluating the impact of adopting FIN 47 on its fmancial position and results of operations.
EITF No. 04-
In March 2005, the Emerging Issues Task Force (the "EITF") issued EITF No. 04-Accountingfor Stripping Costs Incurred during
Production in the Mining Industry EITF No. 04-). EITF No. 04-6 requires that stripping costs incurred during the production
phase of a mine are variable production costs that should be included in the costs of the inventory produced (that is, extracted) during
the period that the stripping costs are incurred. EITF No. 04-6 is effective for all fiscal years beginning after December 15, 2005 and is
expected to be adopted by PacifiCorp on April 1, 2006. While the Company is currently evaluating what impact this guidance will
have on its financial statements, its adoption is not expected to have a material impact on PacifiCorp s financial position or 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
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NOTES TO FINANCIAL STATEMENTS (Continued)
(asset) or that an obligation has been incurred (liability) in accordance with the provisions of SFAS No. 71 Accountingfor the Effects
of Certain Types of Regulation. The final outcome, or additional regulatory actions, could change management's assessment in future
periods.
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.
For a detailed view ofPacifiCorp s regulatory assets and liabilities see page 232 Regulatory Assets and page 278 Regulatory
Liabilities of this FERC Fonn 1.
Note 3 - Derivative Instruments
PacifiCorp s derivative instruments are recorded on the comparative Balance Sheets as assets or liabilities measured at estimated fair
value, unless they qualify for certain exemptions permitted under SFAS No. 133 Accountingfor Derivative Instruments and Hedging
Activities as amended. Changes in fair value ofPacifiCorp s recorded derivative contracts are recognized immediately in the
Statements of Income and Retained Earnings, except for contracts probable of recovery in rates based upon approval in states
comprising substantially all ofPacifiCorp s retail revenues. The net change in fair value for such contracts is deferred as either a
regulatory asset or liability until realized. Umealized gains and losses on derivative contracts held for trading purposes, are presented
gross in Other income and Other income and deductions. Umealized gains and losses from derivative contracts not held for trading
purposes are presented gross in Other income and Other income and deductions.
Umealized losses and (gains) on energy sales and purchase contracts are affected by fluctuations in forward market prices for
electricity and natural gas. The following table summarizes the amount of pre-tax unrealized losses and (gains) included within the
Statements of Income and Retained Earnings associated with changes in fair value ofPacifiCorp s derivative contracts.
Twelve Months Ended
December 31,
2005 2004
(368.(85.
326.78.
(42.(6.
(Millions ofdollars)
Other Income:
Miscellaneous Nonoperating Income (421)
Other Income Deductions:
Other Deductions (426.
Total unrealized (gain) loss on derivative contracts
The following table summarizes the changes in fair value ofPacifiCorp 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, 2005, and the portion of those amounts that has been recognized as a regulatory net (liability) because the contracts are
receiving recovery in retail rates.
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NOTES TO FINANCIAL STATEMENTS (Continued
Fair value of contracts outstanding at December 31 , 2005
Regulatory
Net Net asset
Asset (Liability)(Liability) (c)
(271.3)277.9
(34.35.
(52.52.
499.(458.
141.6 (92.
(M illions of dollars)
Fair value of contracts outstanding at December 31 2004
Contracts realized or otherwise settled during the period
Changes in fair values attributable to changes in
valuation techniques and assumptions (a)
Other changes in fair values (b)
(a)Effective March 31 2005, PacifiCorp adjusted its estimate of the period covered by market quotes from
three years to six years due to the increased availability of verifiable market quotations. This change had the
effect of decreasing the fair value of non-trading contracts by $52.7 million, offset by an increase in
regulatory net assets of the same amount.
Other changes in fair values include the effects of changes in market prices, inflation rates and interest rates
including those based on models, on new and existing contracts.
Net unrealized losses (gains) related to derivative contracts included in rates are recorded as a regulatory net
asset (liability).
(b)
(c)
Weather derivatives - PacifiCorp cUlTently has a non-exchange traded streamflow weather derivative contract to reduce PacifiCorp
exposure to variability in weather conditions that affect hydroelectric generation. Under the agreement, PacifiCorp pays an annual
premium in return for the right to make or receive payments if streamflow levels are above or below certain thresholds. PacifiCorp
estimates and records an asset or liability corresponding to the total expected future cash flow under the contract in accordance with
EITF No. 99-Accountingfor Weather Derivatives. The net liability recorded for this contracts was zero at December 31, 2005 and
$1.7 million at December 31, 2004. PacifiCorp recognized a gain of $9.4 million for the twelve months ended December 31, 2005 and
a gain of $2.9 million for the twelve months ended December 31, 2004.
Note 4 - Related-Party Transactions
There are no loans or advances between PacifiCorp and ScottishPower or between PacifiCorp and PHI. Loans or advances between
PacifiCorp and ScottishPower or PHI generally require state regulatory approval. There are intercompany loan agreements that allow
fimds to be lent from PacifiCorp Group Holdings Company ("PGHC") to PacifiCorp, but loans from PacifiCorp to PGHC are
prohibited. There are intercompany loan agreements that allow fimds to be lent between PacifiCorp and Pacific Minerals, Inc. ("PMI"
a wholly owned subsidiary ofPacifiCorp. PacifiCorp does not maintain a centralized cash or money pool. Therefore, funds of each
company are not commingled with fimds of any other company. Other affiliate transactions that PacifiCorp enters into are subject to
certain approval and reporting requirements of the regulatory authorities.
The following tables detail PacifiCorp s transactions and balances with unconsolidated related parties:
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NOTES TO FINANCIAL STATEMENTS (Continued)
(M illions of dollars)December 31 December 31
2005 2004
Amounts due from affiliated entities:
SPUK (a)0.4
PHI and its subsidiaries (b)
PacifiCorp subsidiaries (c)1.0
Prepayments to affiliated entities:
PHI and its subsidiaries (d)41.9
DIlL (e)1.8
1.8 41.9
Amounts due to affiliated entities:
SPUK (f)
PHI and its subsidiaries (g)11.2
PacifiCorp subsidiaries (h)28.
17.5 48.4
Deposits received from affiliated entities:
PHI and its subsidiaries (i)1.1
Twelve Months Twelve Months
(M illions of dollars)Ended Ended
December 31 December 31
2005 2004
Revenues from affiliated entities:
PHI and its subsidiaries (i)6.4
Expenses incurred from affiliated entities:
SPUK (f)15.17.
PHI and its subsidiaries (d)19.17.
PacifiCorp subsidiaries (j)71.4 76.
DIlL (e)5.4
112.4 111.6
Expenses recharged to affiliated entities:
SPUK (a)6.4
PHI and its subsidiaries (b)
PacifiCorp subsidiaries (c)20.15.
36.26.
Interest expense to affiliated entities:
PHI and its subsidiaries (k)
PacifiCorp subsidiaries (I)
0.4
(a)These receivables and expenses primarily represent costs associated with retention agreements and
severance benefits reimbursable by Scottish Power UK pic ("SPUK"), an indirect subsidiary of
ScottishPower, and amounts allocated to SPUK by PacifiCorp for administrative services provided under
ScottishPower s affIliated interest cross-charge policy. In addition, PacifiCorp recharged to SPUK payroll
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NOTES TO FINANCIAL STATEMENTS (Continued)
costs and related benefits of PacifiCorp employees working on international assignment in the United
Kingdom during each of the three and nine months ended December 31, 2005 and 2004.
(b) AmOl.mts shown pertain to activities ofPacifiCorp with PHI and its subsidiaries. Expenses recharged reflect
costs for support services to PHI and its subsidiaries.
(c) Amounts shown reflect costs recharged for support services to PacifiCorp s subsidiaries.(d) Includes prepaid income taxes paid to PHI of$41.9 million at December 31 2004. PHI is the tax paying
entity for PacifiCorp. Also includes expenses related to operating lease payments for the West Valley
facility, located in Utah and owned by West Valley Leasing Company, LLC ("West Valley ). West Valley
is a subsidiary ofPPM Energy, Inc. ("PPM"), which is a subsidiary of PHI. Certain costs associated with the
West Valley lease are prepaid on an annual basis. PacifiCorp recorded lease expense in the amount of$17.
and $17.1 for the West Valley facility for the twelve months ended December 31 , 2005 and 2004.
( e) PacifiCorp began participating in a captive insurance program provided by Domoch International Insurance
Limited ("DIlL"), an indirect wholly owned consolidated subsidiary ofScottishPower, in May 2005. DIlL
covers all or significant portions of the property damage and liability insurance deductibles in many of
PacifiCorp s current policies, as well as overhead distribution and transmission line property damage.
PacifiCorp has no equity interest in DIlL and has no obligation to contribute equity or loan funds to DIlL.
Premium amounts are established to cover loss claims, administrative expenses and appropriate reserves, but
otherwise DIlL is not operated to generate profits. Certain costs associated with the captive insurance
program are prepaid.
(t) These liabilities and expenses primarily represent amounts allocated to PacifiCorp by SPUK for
administrative services received under the cross-charge policy. Cross-charges from SPUK to PacifiCorp
amounted to $14.4 million and $12.6 for the twelve months ended December 31 2005 and 2004. These
costs were recorded in Operations and maintenance expense and Other income and deductions. SPUK also
recharged PacifiCorp for payroll costs and related benefits of SPUK employees working on international
assignments with PacifiCorp in the United States for the twelve months ended December 31 2005 and 2004.
(g) The amount shown is the current portion of federal and state income taxes for December 31 , 2005 and state
taxes for December 31, 2004 payable to PHI. PHI is the tax paying entity for PacifiCorp.
(h) Amounts due to affiliates of $8.9 million for December 31, 2005 primarily represents, $1.6 million in
short-term demand loans, $7.3 million in coal purchases payable to PMI. Amounts due to affiliates of $28.
million for December 31, 2004 represents, $20.5 million in short-term demand loans and $8.4 million in
coal purchases payable to PM!.
(i) These revenues and the associated deposits relate to wheeling services billed to PPM, a subsidiary of PHI.
PacifiCorp provides these services to PPM pursuant to PacifiCorp s FERC-approved open access
transmission tariff, which requires PacifiCorp to make transmission services available on a
non-discriminatory basis to all interested parties.
(j) Represents coal purchase and extraction expenses of$70.0 million and $75.1 for the twelve months ended
December 31, 2005 and 2004 from the Trapper and Bridger coal mines, as well as environmental services
provided by PacifiCorp Environmental Remediation Company ("PERCO") of $1.4 million and $1.6 for the
twelve months ended December 31, 2005 and 2004.(k) Represents interest on short-term demand loans made to PacifiCorp by PGHC, in accordance with regulatory
authorization and interest on deposits from PPM. Interest rates on related-party transactions approximate the
lender s short-term borrowing cost or cost of capital as required by the relevant regulatory approval or
exemption.
(1) Includes interest on short-tenn demand loans made to PacifiCorp by PM!
Note 5 - Financing Arrangements
During the twelve months ended December 31 2005, PacifiCorp entered into three new standby letters of credit which totaled $56.
million at December 31 2005.
During the twelve months ended December 31, 2005, PacifiCorp amended $421.3 million of its existing committed standby bond
purchase and letter of credit agreements, which provide credit enhancement and liquidity support for eight series of variable-rate
pollution control revenue bond obligations. Changes included an exclusion of the acquisition ofPacifiCorp by MidAmerican as an
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NOTES TO FINANCIAL STATEMENTS (Continued)
event of default under the agreements.
In August 2005, PacifiCorp amended and restated its existing $800.0 million committed bank: revolving credit agreement. Changes
included an increase to 65.0% in the covenant not to exceed a specified debt-to-capitalization percentage, extension of the tennination
date to August 29 2010 and an exclusion of the acquisition ofPacifiCorp by MidAmerican as an event of default under the agreement.
Note 6 - Long-Term Debt
In September 2005, the SEC declared effective PacifiCorp s shelf registration statement covering $700.0 million of future first
mortgage bond and unsecured debt issuances. PacifiCorp has not yet issued any of the securities covered by this registration statement.
In June 2005 , PacifiCorp issued $300.0 million of its 5.25% Series of First Mortgage Bonds due June 15 2035. PacifiCorp used the
proceeds for the reduction of short-term debt, including the short-term debt used in December 2004 to redeem its 8.625% Series of
First Mortgage Bonds due December 13, 2024 totaling $20.0 million.
During March 2005, the maturity dates were extended to December 1, 2020 for three series of variable-rate pollution-control revenue
bonds totaling $38.1 million.
PacifiCorp made interest payments, net of capitalized interest, of $236.2 million for the twelve months ended December 31, 2005 and
$218.0 million for the twelve months ended December 31, 2004.
Note 7 - Common Shareholder s Equity
At December 31, 2005 PacifiCorp had $3.6 million in Appropriated retained earnings - amortization reserve, federal. This is in
accordance with the requirements of hydroelectric relicensing projects.
On December 30, 2005, PacifiCorp issued 11 627 907 shares of its common stock to its direct parent company, PHI, in consideration
of the capital contribution of$125.0 million in cash made by PHI on that date.
On September 30, 2005, PacifiCorp issued 11 617 101 shares of its common stock to its direct parent, PHI, in consideration of the
capital contribution of$125.0 million in cash made by PHI on that date.
On July 21 2005, PacifiCorp issued 11 737 090 shares of its common stock to its direct parent, PHI, in consideration of the capital
contribution of$125.0 million in cash made by PHI on June 30, 2005.
Proceeds from each issuance were used for the reduction of short-term debt.
Note 8 - Commitments and Contingencies
PacifiCorp follows SF AS No.Accountingfor Contingencies to detennine accounting and disclosure requirements for
contingencies. PacifiCorp operates in a highly regulated environment. Governmental bodies such as the FERC, the SEC, the Internal
Revenue Service, the Department of Labor, the United States Environmental Protection Agency (the "EPA") and others have authority
over various aspects ofPacifiCorp 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.
Litil!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 complaint 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 September 2004, the Klamath Tribes filed their first amended complaint adding claims of damage to their treaty rights to fish for
IFERC FORM NO.1 (ED. 12-88) Page 123.
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NOTES TO FINANCIAL STATEMENTS (Continued)
sucker and steelhead in the headwaters of the Klamath River. The complaint seeks in excess of $1.0 billion in compensatory and
punitive damages. In July 2005, the District Court dismissed the case and in September 2005 denied the Klamath Tribes' request to
reconsider the dismissal. In October 2005, the Klamath Tribes appealed the District Court's decision to the Ninth Circuit Court of
Appeals and briefing is scheduled to be completed by March 2006. PacifiCorp believes the outcome of this proceeding will not have a
material impact on its financial position, results of operations or liquidity.
In October 2005 , PacifiCorp was added as a defendant to a lawsuit originally filed in February 2005 in state district court in Salt Lake
City, Utah by USA Power, LLC and its affiliated companies, USA Power Partners, LLC and Spring Canyon, LLC (collectively, "USA
Power ), against Utah attorney Jody L. Williams and the law firm Holme, Roberts & Owen, LLP, who represent PacifiCorp on various
matters from time to time. USA Power is the developer of a planned generation project in Mona, Utah called Spring Canyon, which
PacifiCorp, as part of its resource procurement process, at one time considered as an alternative to the Currant Creek Power Plant.
USA Power s complaint alleges that PacifiCorp misappropriated confidential proprietary infonnation in violation of Utah's Uniform
Trade Secrets Act and accuses PacifiCorp of breach of contract and related claims. USA Power seeks $250.0 million in damages
statutory doubling of damages for its trade secrets violation claim, punitive damages, costs and attorneys' fees. PacifiCorp believes it
has a number of defenses and intends to vigorously oppose any claim of liability for the matters alleged by USA Power. Furthermore
PacifiCorp expects that the outcome of this proceeding will not have a material impact on its financial position, results of operations or
liquidity.
In October 2005, the Utah Committee of Consumer Services (the "CCS"), a state utility consumer advocate, filed a request for agency
action with the Utah Public Service Commission (the "UPSC"). The request seeks an order requiring PacifiCorp to return to Utah
ratepayers certain monies collected in Utah rates for taxes, which the CCS alleges were improperly retained by PacifiCorp s parent
company, PIll. The CCS has publicly announced it is seeking a refund of at least $50.0 million to Utah ratepayers. In November 2005
PacifiCorp filed a response with the UPSC seeking dismissal of the request. In December 2005 that request was denied. PacifiCorp
disagrees with, and intends to vigorously oppose, the claims made by the CCS. A procedural schedule to hear the matter has not beenestablished.
In April 2004, PacifiCorp filed a complaint with the federal district court in Wyoming challenging the Wyoming Public Service
Commission (the "WPSC") decision made in March 2003 to deny recovery of the Hunter No. I replacement power costs and certain
deferred excess net power costs. The complaint was filed 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 November
2004, the court denied the defendants' motion to dismiss the complaint. In January 2005, the defendants appealed the court's ruling on
the motion to dismiss and requested a stay of the underlying litigation. The defendants ' appeal on sovereign immunity grounds and a
decision on the issue of whether the defendants' notice of appeal was timely are pending at the Tenth Circuit Court of Appeals.
In February 2006, PacifiCorp and certain parties intervening in its pending Wyoming general rate case reached a settlement of the
terms ofPacifiCorp s general rate case request. PacifiCorp also agreed to dismiss its federal lawsuit challenging the WPSC decision,
and the defendants agreed to dismiss their pending appeal, subject to final approval of the general rate case settlement.
From time to time, PacifiCorp is also a party to various other legal claims, actions, complaints and disputes, certain of which involve
material amounts. PacifiCorp recorded $7.1 million in reserves as of December 31 , 2005 related to various outstanding legal actions
and disputes, excluding those discussed below. PacifiCorp currently believes that disposition of these matters will not have a material
adverse effect on PacifiCorp s financial position, results of operations or liquidity.
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 2005
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. In the
future, PacifiCorp expects to incur significant costs to comply with various stricter air emissions requirements. These potential costs
IFERC FORM NO.(ED. 12-SS) Page 123.
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NOTES TO FINANCIAL STATEMENTS (Continued)
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 financial position or results of operations.
Hydroelectric Relicensinl!
PacifiCorp s hydroelectric portfolio consists of 51 plants with an aggregate plant net capability of 1 159.4 MW. The FERC regulates
99.0% of the installed capacity through 18 individual licenses. Several ofPacifiCorp 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. PacifiCorp has accwnulated approximately $67.3 million in costs as of December 31 2005 for
ongoing hydroelectric relicensing that are reflected in assets on the Balance Sheet. PacifiCorp expects that these and future costs will
be included in rates and, as such, will not have a material adverse impact on PacifiCorp s financial position or results of operations.
In October 2005, the new FERC license for the North Umpqua hydroelectric project became final under the terms of the North
Umpqua Settlement Agreement. Prior to this date, the license had been effective, but not final, because environmental groups had
challenged its legality before the FERC and in federal court. In September 2005, the Ninth Circuit Court of Appeals issued an order
upholding the new license. Since the Court's order was not appealed within the allowed time, all legal challenges of the FERC license
order have been exhausted and the license is final for purposes of recording liabilities. PacifiCorp is committed, over the 35-year life
of the license, to fund approximately $47.5 million for environmental mitigation and enhancement projects. As a result of the license
becoming final, PacifiCorp recorded additional liabilities and intangible assets in October 2005 amounting to a present value of $11.
million. At December 31, 2005, the liability recorded for all North Umpqua obligations amounted to a present value of $22.9 million.
Enron Corp. Reserves
In December 2001, Eoron Corp. declared bankruptcy and defaulted on certain wholesale contracts. PacifiCorp had fully reserved for
its $8.0 million Enron Corp. receivable. PacifiCorp sold its bankruptcy claim to a third party during the first quarter of calendar 2005
for proceeds of $1.7 million.
FERC Issues
California Refund 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
order issued by the FERC in this proceeding. In addition, beginning 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 Refund 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 Ninth Circuit Court of Appeals for review of the FERC's final order.
A decision from the Ninth Circuit 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. Also 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 were filed by March 2005. In August 2005
the Ninth Circuit Court of Appeals dismissed PacifiCorp s appeal. In September 2005, PacifiCorp filed a request for rehearing of the
Ninth Circuit's decision. This request was denied by the Ninth Circuit in October 2005. PacifiCorp will not pursue further review of
the case; therefore, the Ninth Circuit's dismissal is final.
FERC Show-Cause Orders - In May 2002, PacifiCorp, together with other California electricity market participants, responded to data
IFERC FORM NO.1 (ED. 12-SS) Page 123.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/20/2006 2005/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
requests ftom 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 requests for rehearing of the FERC's fInal order. A decision ftom the FERC on the rehearing request is pending.
FERC Market Power Analvsis - Pursuant to the FERC's orders granting PacifiCorp authority to sell capacity and energy at
market-based rates, PacifiCorp and certain of its affiliates are required to submit a joint market power analysis every three years. Under
the FERC's current policy, applicants must demonstrate that they do not possess market power in order to charge market-based rates
for sales of wholesale energy and capacity in the applicants' control areas. An analysis demonstrating an applicant's passage of certain
threshold screens for assessing generation market power establishes a rebuttable presumption that the applicant does not possess
generation market power, while failure to pass any screen creates a rebuttable presumption that the applicant has generation market
power. In February 2005, PacifiCorp submitted a joint triennial market power analysis in compliance with the FERC's requirements.
The analysis indicated that PacifiCorp failed to pass one of the generation market power screens in PacifiCorp s eastern control area
and in Idaho Power Company s control area. In May 2005, the FERC issued an order instituting a proceeding pursuant to Section 206
of the Federal Power Act to determine whether PacifiCorp may continue to charge market-based rates for sales of wholesale energy
and capacity in its east control area. Under the terms of the order, PacifiCorp and its affiliated co-applicants were required to submit
additional information and analysis to the FERC within 60 days to rebut the presumption that PacifiCorp has generation market power.
In June and July 2005, PacifiCorp filed additional analysis in response to the FERC's May 2005 order. In January 2006, the FERC
requested PacifiCorp to amend its previous filings with additional analysis. If the FERC ultimately finds that PacifiCorp has market
power, PacifiCorp will be required to implement measures to mitigate any exercise of market power, which may result in decreased
revenues and/or increased operating expenses. PacifiCorp believes the outcome of this proceeding will not have a material impact on
its financial position or results of operations.
Note 9 - Retirement Benefit Plans
The components of net periodic benefit cost for the twelve months ended December 31 , 2005 and 2004 are as follows:
Retirement Plans Other Postretirement Benefits
Twelve Twelve Twelve Twelve
Months Ended Months Ended Months Ended Months Ended
(M illions of dolla~s)December 31 December 31 December 31 December 31
~J.'.-2005 2004 2005 2004
Service Cost 29.30.
Interest Cost 74.73.30.31.9
Expected Return on Plan Assets (a)(77 .(78.(26.(26.
Amortization of Unrecognized Net Obligation 8.4 12.12.
Amortization of Unrecognized Prior Service Cost 1.3 1.4 1.6
Amortization of Unrecognized Loss 18.
Net Periodic Benefit Cost 54.41.9 29.26.
( a) The market-related value of plan assets, among other factors, is used to determine expected return on plan
assets and is calculated by spreading the difference between expected and actual investment returns over a
IFERC FORM NO.1 (ED. 12-88) Page 123.
Nanie of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)
PacifiCorp (2)A Resubmission 03/20/2006 2005/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
five-year period beginning in the first year in which they occur.
Employer Contributions
PacifiCorp contributed $63.7 million to its retirement plans and $25.2 million to its other postretirement plans during the twelve
months ended December 31 , 2005.
Note 10 - 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$185.1million and $122.8 million for the twelve months ended December
, 2005 and December 31, 2004. PacifiCorp keeps its accounting records on a fiscal-year basis for SEC financial reporting purposes.
The fiscal year end is March 31 st. Annual fiscal year-end tax adjustments are performed in March. These adjustments generally result
in larger changes to various tax accounts between "current-year end of quarter balances" and "prior year end balances" in the first
quarter 3-Q (first quarter of the calendar year) report than in subsequent quarters.
The total accrued federal and state income tax expense are as follows:
Twelve Twelve
(M illions of dollars)Months Ended Months Ended
December December
Page Line Description 2005 2004
114 15 Income Taxes Federal 409.95.45.
114 16 Income Taxes Other 409.(12.
114 17 Provision for Deferred Income Taxes 410.690.715.
114 18 (Less) Provision for Deferred Income Taxes 411.1 623.625.
114 19 Investment Tax Credit 411.4 (5.(5.
117 53 Income Taxes Federal409.20.
117 54 Income Taxes Other 409.1.1
117 55 Provision for Deferred Income Taxes 410.1.3 0.5
117 56 (Less) Provision for Deferred Income Taxes 411.2
117 57 Investment Tax Credit 411.5
117 58 (Less) Investment Tax Credits 420
185.122.
PacifiCorp has established, and periodically reviews, an estimated contingent tax reserve on Balance Sheets to provide for the
possibility of adverse outcomes in tax proceedings. The current-year accruals are primarily attributable to new issues identified for the
tax years ended after March 31, 2000. PacifiCorp anticipates that final settlement and payment on settled issues and other unresolved
issues will not have a material adverse impact on its financial position or results of operations.
PacifiCorp made net income tax payments of $86.1 million for the twelve months ended December 31 , 2005 and $89.5 million for the
twelve months ended December 31, 2004. The income tax payments include payments for current federal and state income taxes, as
well as amounts paid in settlement of prior years' liabilities as a result of income tax proceedings.
Note 11 - Subsequent Events
On January 27, 2006, PacifiCorp s Board of Directors declared a dividend on common stock of$0.163 per share totaling $56.6 million
IFERC FORM NO.1 (ED. 12-SS) Page 123.13
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Oa, Yr)
PacifiCorp (2)A Resubmission 03/20/2006 2005/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
and payable on the earlier of March 31, 2006 or the closing date of the acquisition of PacifiCorp by MidAmerican. If the acquisition of
PacifiCorp closes prior to March 31, 2006, the dividend amount will be reduced pro-rata based on the closing date relative to March
2006.
I FERC FORM NO.1 (ED. 12-88)Page 123.
Name of Respondent This 7!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND 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. .
2. Report in columns (f) 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 Item Unrealized Gains and Minimum Pension Foreign Currency Other
No.Losses on Available-Liability adjustment Hedges Adjustments
for-Sale Securities (net amount)
(a)(b)(c)(d)(e)
1 Balance of Account 219 at Beginning of
Preceding Year 92,529)862 730)
2 Preceding QtrlYr to Date Reclassifications
from Acct 219 to Net Income
3 Preceding QuarterlYear to Date Changes in
Fair Value 101 045 135,429)
4 Total (lines 2 and 3)101,045 135,429)
5 Balance of Account 219 at End
Preceding QuarterlYear 516 998,159)
6 Balance of Account 219 at Beginning of
Current Year 516 998 159)
7 Current QtrlYr to Date Reclassifications
from Acct 219 to Net Income
8 Current QuarterlYear to Date Changes in
Fair Value 914 447 992 768)
9 Total (lines 7 and 8)914 447 992 768)
Balance of Account 219 at End of Current
QuarterlY ear 922 963 990 927)
FERC FORM NO.1 (NEW 06-02)Page 122a
Name of Respondent This ~ort Is: Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr) End of 2005/04PacifiCorp (2) A Resubmission 03/20/2006
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)
( 1 955 259)
(f)
(g)
034 384)
034,384)
989,643)
989,643)
( 78 321)
( 78,321)
( 8 067,964)
FERC FORM NO.1 (NEW 06-02)Page 122b
Net Income (Carried
Forward from
Page 117, Line 78)
Total
Comprehensive
Income
(i)
(j)
IS ~o s: a e 0 epo(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 03/20/2006
SUMMA Y OF UTILITY PLANT AND ACCUMULATED 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
CuITent Yea~Quarter 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
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
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 26,31,32)
308,107 866
36,702 511
14,308,107 866
702,511
27,688,862 27,688 862
372 499 239 372 499 239
205,806
594 604 038
157 193,780
127 502 863
129,967 945
997,534,918
205,806
594 604 038
157 193,780
15,127,502 863
129,967 945
997 534 918
74,409,461
129 967 945
74,409 461
129,967,945
FERC FORM NO.1 (ED. 12-89)Page 200
Gas
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 03/20/2006
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Other (Specify) Other (Specify) Other (Specify) ,
Year/Period of Report
End of 2005/04
Name of Respondent
PacifiCorp
Common Line
No.
FERC FORM NO.1 (ED. 12-89)Page 201
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2). A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
'Schedule Page: 200
Depreciation
Depletion
Total
Line No.18 Column:
650 116 122
40.429.596
690 545 718
IFERC FORM NO.1 (ED. 12-S7) Page 450.
Blank Page
(Next Page is: 204)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) 0 A Resubmission 03/20/2006
ELECTRI PLANT IN SERVICE (Account 101 02, 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)
Account
No.Beginning of Year
(a)b) (c)
1. INTANGIBLE PLANT
(301) Or9anization 26,288,163
(302) Franchises and Consents 106,471,326 083,860
(303) Miscellaneous Intangible Plant 478 907 203 60,517 726
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)611 666,692 601 586
2. PRODUCTION PLANT
A. Steam Production Plant
(310) Land and Land Rights 81,363 567 136,972
(311) Structures and Improvements 767 023 948 830,356
(312) Boiler Plant Equipment 2,493,429,645 675,571
(313) Engines and Engine-Driven Generators
(314) Turbogenerator Units 688,143,409 31,154 372
(315) Accessory Electric Equipment 326 037,350 136 193
(316) Misc. Power Plant Equipment 564,474 285,256
(317) Asset Retirement Costs for Steam Production 25,522 333 939 963
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)4,407 084 726 136,158,683
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 769,293
(331) Structures and Improvements 683 560 376 367
(332) Reservoirs, Dams, and Waterways 272,408,164 369 284
(333) Water Wheels, Turbines, and Generators 79,877 604 677,427
(334) Accessory Electric Equipment 38,455 021 022,224
(335) Misc. Power PLant Equipment 184 246 260
(336) Roads, Railroads, and Bridges 12,450,644 855 515
(337) Asset Retirement Costs for Hydraulic Production 612,683 322
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)509,441 215 224 755
D. Other Production Plant
(340) Land and Land Rights 359,504 20,112 783
(341) Structures and Improvements 16,844 604 108
(342) Fuel Holders, Products, and Accessories 492 844
(343) Prime Movers 178 341,406 166,711,869
(344) Generators 533 418
(345) Accessory Electric Equipment 16,487 397
(346) Misc. Power Plant Equipment 534,784
FERC FORM NO.1 (REV. 12'()3)Page 204
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) , An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
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 joumal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date
Line
( )
f) End ~f Year No.(e)
500 494 16,787,669
117,555,186
737,562 162,044 537,849,411
12,238,056 162 044 672 192 266
700 81,496,795
441 815 301 058 770 111,431
25,755,522 590,872 553 758,822
030,758 334,025 712 601 048
956,321 145,564 329,362 786
310 712,450 25,059,970
29,462 296
37,261,770 128,491 501,853,148
832 30,331 19,681 130
48,714 -45 80,011 168
545,635 280 231 813
477,848 86,077 183
45,329 40,431 916
189,506
075 13,230,084
531 361
251 433 30,376 528 384 161
29,777 502 064
748,874 44,660,586
063,422 309,416 738 839
42,605 288,061 262 722 609
047 985,541 479,920
593 160 34,080,559
106,021 640,805
FERC FORM NO.1 (REV. 12-03)Page 205
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmisslon 03/20/2006
ELECTRIC PLANT IN SERVICE (Account 101 102 3 and 106) (Continued)
Account 1j~lance Additions
No.Beginning of Year
(a)(b)(c)
(347) Asset Retirement Costs for Other Production 492,532 262,682
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)281,086,489 187,154,453
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)197,612,430 343,537,891
3. TRANSMISSION PLANT
(350) Land and Land Rights 88,520,326 682 914
(352) Structures and Improvements 48,878 361 308,409
(353) Station Equipment 868.988 467 382,647
(354) Towers and Fixtures 361 139 132 10,102 226
(355) Poles and Fixtures 484 345 795 770,931
(356) Overhead Conductors and Devices 618,116,181 001,473
(357) Underground Conduit 367 203 297
(358) Underground Conductors and Devices 951 434 178
(359) Roads and Trails 11,370 173 43,444
(359.1) Asset Retirement Costs for Transmission Plant
TOTAL Transmission Plant (Enter Total of lines 48 thru 57)487 677 072 287 163
4. DISTRIBUTION PLANT
(360) Land and Land Rights 183,599 000,076
(361) Structures and Improvements 36,347,414 125,395
(362) Station Equipment 615,480 059 567 976
(363) Storage Battery Equipment
(364) Poles, Towers, and Fixtures 744 285,090 36,945 087
(365) Overhead Conductors and Devices 559,313 562 688 884
(366) Underground Conduit 235,872,409 965,274
(367) Underground Conductors and Devices 553,777,450 29,139,436
(368) Line Transformers 848,847,249 41,617,034
(369) Services 387 957 405 376,716
(370) Meters 181 525 187 12,314 302
(371) Installations on Customer Premises 983 867 827
(372) Leased Property on Customer Premises 49,658
(373) Street Lighting and Signal Systems 53,596,614 2,422 788
(374) Asset Retirement Costs for Distribution Plant
TOTAL Distribution Plant (Enter Total of lines 60 thru 74)257,219,563 228,200,795
5. GENERAL PLANT
(389) Land and Land Rights 881 163 315 347
(390) Structures and Improvements 212 985 408 326,981
(391) Office Fumiture and Equipment 116,229,400 10,354,246
(392) Transportation Equipment 80,511 775 14,273 872
(393) Stores Equipment 340,986 706 082
(394) Tools, Shop and Garage Equipment 504 702 928 758
(395) Laboratory Equipment 067,781 321,046
(396) Power Operated Equipment 105 964 582 14,494 113
(397) Communication Equipment 224 727 448 078,233
(398) Miscellaneous Equipment 613,779 18,432
SUBTOTAL (Enter Total of lines 77 thru 86)861,827 024 817 110
(399) Other Tangible Property
(399.1) Asset Retirement Costs for General Plant
TOTAL General Plant (Enter Total of lines 87, 88 and 89)134 008,604 197 953
TOTAL (Accounts 101 and 106)13,688 184 361 829 825,388
(102) Electric Plant Purchased (See Instr. 8)
(Less) (102) Electric Plant Sold (See Instr. 8)213,554
(103) Experimental Plant Unclassified
TOTAL Electric Plant in Service (Enter Total of lines 91 thru 94)688 397 915 829,825 388
FERC FORM NO.1 (REV. 12-03)Page 206
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
ELECTRIC PLANT IN SERVICE (Account 101 102 103 and 106) (Continued)
Retirements Adjustments Transfers Balance at Line
(d)(e)(f)
End fJ)Year No.
755,214
145,074 515,272 456,580,596
658,277 674 139 5,486 817 905
133 192 -637,719 432 329
102,774 172,630 256 626
10,892,901 10,719,027 900 197,240
301 733 567,472 372 507 097
1,488,508 922,038 504,706 180
097,946 507,880 643,527 588
369 500
944,256
36,935 376 682
017,054 370,317 578 317 498
634,487 107,611 36,656,799
224 471 596,542 844 880
500 201 053,327 630 494 507
285,571 285,571
209 100 107 049 774 914 028
602,447 577 399 999
680,208 247 157,475
253 540 342,461 581 320,885
838 842 21,656 882,647 097
379,281 421 954 840
600,148 187 239,341
660 927 034
658
569,970 449,346
587,355 491,543 446 341,460
228 179 138 15,003,144
959,622 390,572 220 743,339
635,934 203,254 118,744,458
146,518 210,611 849,740
72,589 634,291 13,608 770
86,848 16,787 329,825
45,163 857,149 37,200,813
155,217 3,404,088 114 707 566
908 112 576,336 236 321 233
496 218,476 773,191
37,101,727 739,672 909,282 079
,i,".. ,'i'
""""' . ", ,' ,
76,795 534 716 576 152 127 599
182,296 276 83,255 14,335 796 728
:,',',
182 296,276 213 554 83,255 335 796 728
FERC FORM NO.1 (REV. 12-03)Page 207
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)
PacifiCorp (2) . A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
ISchedule Page: 204 Line No.Column: b
Balance at Balance at
Beginning End of
Line Account Description of Year Additions Retirements Transfers Year
No.(a)(b)(c)(d)(e)(f)
(g)
39921 LAND OWNED IN FEE $ 2,634 916 $ 2 634 916
39922 LAND RIGHTS 55,561 367 (3,108 720)52,452 647
39930 STRUCTURES 45,597,060 306,973 (9,983 548)354 786 37,275,271
39941 SURFACE - PLANT EQUIPMENT 11,236,746 538,998 (136,569)639,175
39942 SURFACE - DRAGLINE
39943 SURFACE - RAILROAD EQUIPMENT 664 816
(664 816)
39944 SURFACE - ELEC. PWR FACILITIES 566,476 566 476
39945 UNDERGROUND - COAL MINE EQUIPMENT 52,450,412 879,608 049,243)54,786 437
(494,340)
39946 LONGW ALL SHIELDS 17,678,600 17,678,600
39947 LONGW ALL EQUIPMENT 582 330 185,601 10,762 131
005 800)
39948 MAINLINE EXTENSION 12,048,536 581,600 13,584,135
(1,046,001)
39949 SECTION EXTENSION 714,341 331 202 828 109
(217,434)
39951 VEIllCLES 644 346 220,041 (62 500)037 811
(764 076)
39952 HEAVY CONSTRUCTION EQUIPMENT 22,225,909 320,152 (266 139)510,169
(18,769,753)
39960 MISCELLANEOUS GENERAL EQUIPMENT 665,091 160,786 082 025
(1,743,852)
39961 COMPUTERS - MAINFRAME 785,412 365 578,123
231 654)
39970 MINE DEVELOPMENT & ROAD EXTENSION 125,222 831,517 31,429,495
(527 244)
399915 COAL MINE ARO
TOTL PLNT USED IN MINING ACTIVITIES $ 272,181 580 $10,380,843 $(39,693,807)$ (23 096) $242 845,
!Schedule 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:
See footnote line 88, column b.
!Schedule Page: 204 Line No.88 Column: g
ee footnote line 88, column b.
!Schedule Page: 204 Line No.93 Column:
PacifiCorp and six other minority owners sold their interest in the I MW Skoolrumcbuck 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 5 2004
with the proceeds, net book value, and selling costs transferred to account 102, Electric plant purchased or sold. Additional closing
costs were booked in December 2004 and cleared to account 102. A letter to the Federal Energy Regulatory Commission (the
FERC") for permission to clear account I 02, Electric plant purchased or sold was approved on May 10, 2005 Docket No.
ACO5-43-000
I FERC FORM NO.1 (ED. 12-87)Page 450.
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(Next Page is: 214)
Name of Respondent This
wort
Is:Date of R~ort Year/Period of Report
PaclfiCorp (1) An Original (Mo, Da, r)End of 2005/Q4
(2) Fi A Resubmission 03/20/2006
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 prope!1Y 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 Descrl~tion and Location
No.Of prorrty in is Account In Utility Service End of Year(b) (c) (d)
1 Land and Rights:
3 Oquirrh Substation 2005 245,812
4 North Hom Mountain Coal Properties 1977 953,014
9 Miscellaneous, each under $250,000 980
Other Property:
Miscellaneous, each under $250,000:
Total 205,806
FERC FORM NO.1 (ED. 12-96)Page 214
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
ISchedule Page: 214 Line No.Column:
Pro e for future 345/138 kV substation to be built in 2009.
chedule Pa e: 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:
Various dates and plans.
IFERC FORM NO.1 (ED. 12-S7) Page 450.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (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 33,830,644
Lewis River Relicensing 382 581
Merwin Relicensing 672,608
Swift Relicensing 239 188
Rogue Relicensing 223,036
EMS SCADA Phase 2 3,484 089
K2 - KWI Commercial Risk System 285,017
Production:
Currant Creek Power Project 164,018 209
Lake Side Capital Build 130 984 522
Huntington Emission Control Equipment 43,284,316
North Umpqua Relicensing Implementation 724 920
Jim Bridger Emission Control Equipment 5,423,737
Wyodak Controls Upgrade 550 922
Huntington U1 Boiler Low Temp. Superheater Replacement 324 254
Wyodak - Rewind Main Generator Stator 883 837
Huntington U1 Scrubber Recycle Piping 816,703
Huntington U1 Scrubber Mist Eliminator Upgrade 282 016
Replace Prospect Flumes 124 591
Jim Bridger U1 Rewind Main Generator Stator 803 177
Lewis River Relicensing Implementation 670 635
Dave Johnston Purch & Install add'i Central Air Compressors 662 093
Huntington U1 Scrubber Absorber Tower Linings 609 372
Hunter FGD Waste Disposal 1,427 211
Naughton Electrical Infrastructure Design 284 021
Jim Bridger U2 Refurbish Generator Field 030 772
Jim Bridger U1 Controls Upgrade 012 815
Transmission:
SW Utah Load Growth Project 364 959
Syracuse Add 345-138kV Transformer (394MVA)345 436
Cache Valley Add. Bridgerland Sw St Ph 1 984 811
Summit-Vineyard (Lake Side) Transmission Project 671,459
Bitter Creek Provide 230kV Service to Anadarko 343 564
Summit-Vineyard (Lake Side) Interconnect 188,026
90th South-Oquirrh Recond 138kV Line 091 123
90th So & Terminal Subs: Loop-in CW Lines 946,711
Calif. Line 38, Replace 71 Poles 150 616
TOTAL 594 604 038
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 2005/Q4
(2) Fi A Resubmission 03/20/2006
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 Unjform 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:
Gordon Ave (Layton): New 138-12.5kV Sub 760,753
70th South #1 New 138-12.5kV 30MVA Sub 274 343
Beall Lane Sub Construct New 115-12kV Sub 495,057
General:
Data Network - Router Replacement 121,818
9.
;..
?:;J'104 830,076i;'
TOTAL 594 604 038
FERC FORM NO.1 (ED. 12-87)Page 216.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
'Schedule 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.
IFERC FORM NO.1 (ED. 12-87) Page 450.
Blank Page
(Next Page is: 219)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PaclflCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
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
,-me Item ~8~~)~Ie~~c 1:"'lam In ~Iecmc I:"lam. !"Ielc 'i~~glfo 'O~~rsNo.ervlce for Future Use
(a)(b)(c)(d)(e)
1 Balance Beginning of Year 463,468,995 463,418,745 25C
2 Depreciation Provisions for Year, Charged to
3 (403) Depreciation Expense 372 668,580 372 668,580
4 (403.1) Depreciation Expense for Asset
Retirement Costs
5 (413) Exp. of Elec. PIt. Leas. to Others
,..
6 Transportation Expenses-Clearing
~ ,
7 Other Clearing Accounts
8 Other Accounts (Specify, details in footnote): 957,804 15'
TOTAL Depree. Prov for Year (Enter Total of 400 628,537 400,626,384 15'
lines 3 thru 9)
Net Charges for Plant Retired:
Book Cost of Plant Retired 168,090,933 168,038,530 52,401
Cost of Removal 33,034,791 33,034 791
Salvage (Credit)10,013,983 10,013,983
TOTAL Net Chrgs. for Plant Ret. (Enter Total 191,111 741 191,059,338 52,40.:
of lines 12 thru 14)
Other Debit or Cr. Items (Describe, details in 559,927
footnote):L;'/"
,"'
Book Cost or Asset Retirement Costs Retired
Balance End of Year (Enter Totals of lines 1 690,545,718 690 545,718
10,15,, and 18)
Section B. Balances at End of Year According to Functional Classification
Steam Production 289,647 911 289,647,911
Nuclear Production
Hydraulic Production-Conventional 231,517,800 231 517,800
Hydraulic Production-Pumped Storage
Other Production 63,309 583 63,309,583
Transmission 975,633,431 975,633,431
Distribution 673,162 230 673,162 230
General 457 274,763 457 274 763
TOTAL (Enter Total of lines 20 thru 27)690,545,718 690 545 718
FERC FORM NO.1 (REV. 12-03)Page 219
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
!schedule Page: 219 Line No.Column: b
Per accounting orders in each of the six States' that PacifiCorp operates in, PacifiCorp reclassifies the Depreciation expense of asset
retirement obli ations as either a re lato asset or liabili
Schedule Pa e: 219 Line No.Column: b
Account 151 Fuel Stock
Account 143.3 Joint Owner Receivable - Depreciation expense billed to Joint Owners
Account 182.3 Other Regulatory Assets
Vehicle Depreciation allocated to O&M based on useage activity
Account 503.1 Blundell Depletion
Account 421 Depreciation for Future Use
Total Other Accounts
$12 406 978
209 733
885 017
352,594
103 483
153
$27 959 957
!schedule Page: 219 Line No.16 Column: b
Other items including:
- Recovery ftom third parties for asset relocations and damaged property
- Insurance recoveries
- Adjustments of reserve related to electric plant sold
- Reclassifications ftom electric plant
$17 559 927
IFERC FORM NO.1 (ED. 12-S7) Page 450.
Name of Respondent This (!)ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/04(2) 0 A Resubmission 03/20/2006
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 eamings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418.1.
...me Description OfTnvesfment Date Acquired Date Of Amount or ,Investment at
No.(a)(b)Mat~ity Beginning of Year(d)
PACIFIC POWER & LIGHT COMPANY
Common Stock 100
SUBTOTAL 100
5 CENTRALIA MINING COMPANY 7/20/1990
Common Stock 000
SUBTOTAL 000
9 ENERGY WEST MINING COMPANY 7/18/1990
Common Stock 000
SUBTOTAL 000
PACIFIC MINERALS, INC 12/31/1991
Common Stock
Undistributed Earnings 60,617,415
SUBTOTAL 60,617 416
GLEN ROCK COAL COMPANY 12/31/1991
Common Stock
SUBTOTAL
INTERWEST MINING COMPANY 12/11/1992
Common Stock 000
SUBTOTAL 000
PACIFICORP ENVIRONMENTAL REMEDIATION COMPANY 8/19/1994
Common Stock 900 000
Capital Contributions 944,419
Undistributed Subsidiary Eamings 837 720
SUBTOTAL 682,139
PACIFIC FUTURE GENERATIONS, INC 9/19/1999
Undistributed Subsidiary Eamings 738
SUBTOTAL 738
ITotal Cost of Account 123.1 $847,5211 TOTAL 69,298,918
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 2005/Q4(2) 0 A Resubmission 03/20/2006
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 (t) 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 (t).
8. Report on Line 42, column (a) the TOTAL cost of Account 123.
equity In ::;uDslCiary Kevenues Tor Year Amount OT Investment at Gain or LOSS Trom Investment LineEarnin~s of Year End ~f Year Disp~sed of No.(t)
100
100
000
000
000
000
332 655
715 240 332 656
000
000
900 000
944,419
840 087 677 807
840 087 522 226
843 581
843 581
554 484 853,402
FERC FORM NO.1 (ED. 12-89)Page 225
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2)A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
ISchedule Page: 224 Line No.15 Column:
Equity earnings from Pacific Minerals, Inc. (PMI) consist of inter -company profit on coal sales from Bridger Coal Company, which
PMIjointly owns with Idaho Power Company, to PacifiCorp and are Dot recorded in account 418., Equity in Earnings of Subsidiary
Companies. In order to eliminate the inter-company profit on the coal sales, PacifiCorp records PMI's earnings as an offset to fuel
expense.
IFERC FORM NO.1 (ED. 12-87)Page 450.
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(Next Page is: 227)
Name of Respondent This
wort
Is:Date of R~rt Year/Period of Report
PacifiCorp (1) An Original (Mo, Da 2005/Q4(2)D A Resubmission 03/20/2006 End of
MATERIALS AND SUPPLIES
i 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)48,450,942 56,631 067 Electric
Fuel Stock Expenses Undistributed (Account 152)
Residuals and Extracted Products (Account 153)
Plant Materials and Operating Supplies (Account 154)
Assigned to - Construction (Estimated)548,576 48,271 495 Electric
Assigned to - Operations and Maintenance
Production Plant (Estimated)'49,279 721 180,564 Electric
8 Transmission Plant (Estimated)754 364 915 364 Electric
Distribution Plant (Estimated)466,633 815 760 Electric
Assigned to - Other (provide details in footnote)littiii Electric
TOTAL Account 154 (Enter Total of lines 5 thru 10)105 246 617 117 959,772
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)153,697,559 174,590 839
FERC FORM NO.1 (ED. 12-96)Page 227
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S An Original (Mo. Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
chedule Pa e: 227 Line No.Column: b
Mining M&S 044 535
General Plant M&S 152.788
197 323
chedule Pa e: 227 Line No.Column:
Mining M&S 624 940
General Plant M&S 151.649
776 589
IFERC FORM NO.1 (ED. 12-S7) Page 450.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2005/04(2)0 A Resubmisslon 03/20/2006 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 2006
No.(Account 158.No.Amt.No.Amt.
(a)(b)(c)(d)(e)
Balance-Beginning of Year
Acquired During Year:
Issued (Less Withheld Allow)
Retumed by EPA iiiiiiiiiiiiiiiPurchaseslTransfers:
Total
Relinquished During Year:
Charges to Account 509 103,622.
Other:
Cost of SaleslTransfers:
J. P. Morgan 10,000.
Total 10,000.
Balance-End of Year 65,520.77,795.
Sales:
Net Sales Proceeds(Assoc. Co.
Net Sales Proceeds (Other)10,000.
Gains 10,000.
Losses
Allowances Withheld (Acct 158.
"",
Balance-Beginning of Year 259.259.
Add: Withheld by EPA
Deduct: Retumed by EPA 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 This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)2005/Q4(2)0 A Resubmission 03/20/2006 End of
Allowances (Accounts 158.1 and 158.(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 gains/losses 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 identify 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 identify 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.
2007 2008 Future Years Totals Line
No.Amt.No.Amt.No.Amt.No.Amt.No.
(f)
(g)
(h)(i)(k)(I)(m)
156,643.00 156,643,00
103,622,
10,000.
10,000,
' 31
10,000,
10,000.
259.00 2,259.00 110,921.00 119,957.00
528.528.
269.528.
259.
259.
FERC FORM NO.1 (ED. 12-95)Page 229
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/04(2) n A Resubmission 03/20/2006
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.
LIne Description of Unrecovered Plant rota I 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 YearCommission Authorization to use Ace 182.Charged
and period of amortization (mo, yr to mo, yr))
(a)(b)(c)(d)(e)(f)
Unrecovered Plant: Trojan Nuclear 10,188,749 407 674 863 513,886
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 630,131 151 304,105 326,026
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
v..mortization Period: 04/2001
through 03/2006
TOTAL 16,818,880 978,968 839,912
FERC FORM NO.1 (ED. 12-88)Page 23Gb
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(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 2005/04(2) 0 A Resubmission 03/20/2006
0 HER REGULATORY ASSETS (Account 182.
1. Report below the particulars (details) called for concE!rning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 162.3 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 vvn!len OfT uunng vvnnen OfT uunng Current QuarterlYear
Current the QuarterlYear the Period
QuarterlYear Account Charged Amount
(a)(b)(c)(d)(e)(f)
Deferred Regulatory Expense 188.351 341 002 529,353
Califomia DSM Regulatory Asset 259.101)731 908 14,614 271,9843 _5);",,'387.413 820.079 908 019.458 188 034
,,5,,:5,20,033 559 908 13,940,355 093,204
Washington DSM Regulatory Asset 594,147 908 165.131 570,984
449.084 32.407 908 108,515 372,976
Transition Plan -ID (5)696,989 930.696.989
Transition Plan - OR (10)811,585 930.972.815 17,838,770
Transition Plan - UT (5)785,353 930.785.353
Transition Plan - WY West (5)315,277 930.315.277
Transition Plan - WY East (5)781.764 930.781 764
FAS 109 Deferred Income Taxes Electric 500,987 501
":'
15.640,347 485 147,154
SB 1149 Implementation Costs OR Retail Access 764.102 098,732 407.556,004 15,306,830
Y2K Expense 98-00 OR (7)322,481 930.263,100 59,381
98 Early Retirement OR 11,030,640 930.676.947 353,893
Glenrock Mine Excluding Reclamation UT (10)336,021 930.302.400 033,621
94-98 Fed/State Income Tax Audit Payments-ID 314 756 314.756
Deferred Excess Net Power Costs OR UM995 25,880,915 25.880.915
Deferred Excess Net Power Costs OR UE116 116,786 10.017 126,803
Environmental Costs (10)938,679 051 191 925 236,911 752,959
Deferred Cost of TOU Guarantee 742 804
IDAI Costs No. CA Direct Access 304,660 407.333,104 971 556
Cholla PlantTransaction Costs (26)14,123.848 557 122.426 13,001,422
Chona PlantTransaction Costs OR 677 148)53.813 ~23,335
Cholla Plant Transaction Costs WA ( 1 220.662)007 123,655
Cholla Plant Transaction Costs ID 414.914)973 381,941
Washington Coistrip #3 (22)839,387 456.52.188 787,199
Trail Mountain Mine Closure Costs 609.985 151 946,575 663,410
Trail Mountain Mine - Deseret Settlement 750203)617.421 132,782
FAS133 Derivative Net Regulatory Asset 277,864.573 277.864,573
FAS 87/88 Pension UT 477.042 930.159014 318,028
Noell Kempf CAP UT 089 930.19,332 757
P&M Strike Amort UT 499,083 930.299,449 199,634
Energy Trust of Oregon 8B1149 13,533 153 19.686
BPA Idaho Balancing Account 880.704 254 880,704
Retail Access Project INC.731.859 263 703 995.562
Reg Asset Min. Pension Liab. Adj.226.225,103 430 637 280,655,740
Asset Retirement Obligations Regulatory Difference 24.211,992 334.194!~~~;;;;i'
, "
282.092 28.264,094
DSM Regulatory Assets - Conv 128,728 396.102 524,830
DSM Regulatory Assets - RecJass 284 163)865,400 254 281,645 299,592
UT DSM AC-DLC Program
Sch 781 Direct Access Shopping Incentive 640,807 840,807
TOTAL 191,062.740 75,293,431 381,112,753 885,243,418
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PaciflCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
Column:
Column:
Column:
Column: d
Line No.Column: d
Line No.Column: d
Line No.Column: d
Line No.Column: d
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) Fi A Resubmission 03/20/2006
M SCELLANEOUS DEFFERED DEBITS (Account 186)
1. Report below the particulars (details) called for conc~ming 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 ~(:COunt Amount End of YearChar~ed
(a)(b)(c)(e)(f)
Joseph Settlement (20)797 399 557 137,381 660 018
Firth Cogeneration Buyout (10)444 080 557 444 080
Lacomb Irrigation (24)781,050 557 45,720 735 330
Facilities and Properties 704 143 84,847
Bogus Creek (42)448,240 557 280 1,406 960
Bogus Creek settlement (7)118 000 118 000
Intangible Pension Asset:
SERP Plan 608 000 327 007 935,007
Pension Intangible Asset 33,176,000 228.074 000 102 000
Mead Phoenix Availability
& Trans Charge (50)023 320 565 377 760 15,645 560
Financing Costs Deferred 289 930.289
Buffalo Settlement (7)
Lakevlew Buyout (13)176 725 557 43,280 133,445
TGS Buyout (20)233,391 557 473 217,918
Hermiston Swap (20)250,050 557 539,572 710,478
Deferred Longwall Costs 604,978 972,367 577,345
Transition Costs - WA (5)057 694 930.057 694
Hayden Settlement (6)319 916 151 319,916
Northwest Power Pool 130,402 566 130,402
Other Deferred Debits with
Amounts less than $50,000 220 994 66,934 287 928
Deferred Aquila Streamflow
Hedge Costs 458,330 555 1,458 330
Point to Point Transmission 597 419 \Vanous'
",',
498,152 1 ,099 267
Deferred Costs Wyodak
Settlement (22)033,272 151 335,182 698 090
Misc. Work in Progress
Deferred Regulatory Comm.000 182.000Expenses (See pages 350 - 351)
TOTAL 78,628,533 950,331
FERC FORM NO.1 (ED. 12-94)Page 233
Name of Respondent This '(!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) DA Resubmission 03/20/2006
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 166 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 ~pcounl Amount End of Year Char~ed
(a)(b)(c)(e)(f)
2 Jim Boyd Hydro Buyout (11)752 645 557 860 669 785
Deferred Shelf Registration Cos 62,831 216 489 279 320
Unamortized Credit Agmt Costs 335,154 76,279 411 433
Unamortized PCRB LOC/SBBPA 081,935 290 932 372 867
Unamortized PCRB Mode Conv Cost 902 163 427 128 040 774 123
Deferred Chrgs-Water Rights 725,776 725,776
PropertY Damage Repairs 796 (Various'.796
Emission Reduction Credits 406,980 406 980
Mine Dep n Clearing 15,854 854
Misc. Work in Progress
Deferrea Regulatory Comm.000 182.000Expenses (See pages 350 - 351)
TOTAL 628,533 65,950,331
FERC FORM NO.1 (ED. 12-94)Page 233.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)
PacifiCorp I (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
!schedule Page: 233
Account 142
Account 419
Account 557
ISchedule Page: 233.
Account 165.
Account 505.5
Line No.Column: d
Line No.Column: d
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2005/Q4
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmlssion 03/20/2006
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.
No.
Electric
Regulatory Liabilities
3 Employee Benefits
4 FAS 133 Derivatives
5 BETC Credit Carryforward
8 TOTAL Electric (Enter Total of lines 2 thru 7)
9 Gas
ocabon
(a)
329,770,325
167,963 538
115,933,333
504 700
315,652,418
181 198,165
45,748 981
892,824
Other
TOTAL Gas (Enter Total of lines 10 thru 15
Other (Specify)
TOTAL (Acct 190) (Total of lines 8, 16 and 17)767 958 464 687 255 514
Notes
FERC FORM NO.1 (ED. 12-88)Page 234
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 0 An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
'Schedule Page: 234 Line No.Column:
Account Subdivisions
DT A Misc. Timing Difference - PM!
DTA Rent Expense (Safe Harbor Lease) - PMI
DTA Bridger Sec. 471 Adjustment - PMI
DT A Bridger Reclamaton Trust Earnings - PMI
DTA U ofWY Contract Amort - Prepaid
DTA DefReg Asset - Transmission Service Deposit
DTA FAS 143 ARO Liability
DT A Bad Debts Allowance - Cash Basis
DTA Injuries & Damages Accrual- Cash Basis
DTA M&S Inventory Write-Off
DTA Def. Reg Asset - Foote Creek Contract
DTA Redding Contract - Prepaid
DTA Distribution O&M Amort of Write off
DTA Weather Derivatives
DTA Amort of Debt Disc & Exp
DT A Trail Mountain Accrued Liabilities
DTA Montana Sale Accrual
DT A Purchase Card Trans Provision
DTA Misc. Current and Accrued Liability
DT A Defer MagCorp Revenues
DTA Centralia Sale
DTA Bogus Creek Settlement
DTA Special Assessment - DOE
DTA Extraction Tax Accrual- Cash Basis
DTA Final Reclamation - Cash Basis
DT A Amortization Overburden
DTA Merger Cost Amort
DT A Minimum SERP Liability - OCI
DTA Amort of Projects - Klamath Engineering
DT A Legal Reserve
DTA Sec. 263A Inventory Change - PM!
DTA Unearned Joint Use Pole Contract Rev.
DT A Oregon BETC Credits
DTA Wasatch Workers Comp Reserve
DTA 610.010 NOPA 103 99-00 RAR
DTA 610.035N NOPA 90 99-00 RAR
DTA 610.090 NOPA 10299-00 RAR
DTA 610.075 NOPA 89 99-00 RAR
DTA 610.070N NOPA 88 99-00 RAR
DT A 61 0.020N NOP A's 72, 73 91 99-00 RAR
DTA 610.100N Amort NOPA's 99-00 RAR
DT A 61 0.020N NOP A's 11 0, 111 , & 130 99-00 RAR
DTA 610.105N NOPA's 110, 111 , & 13099-00 RAR
DTA 425.120 Bear River Settlmt Agrmt
DTA 425.110 Tenant Lease Allow-PSU Call Center
DTA 210.000, Prepaid Ins. Cont. Reserve
DTA Reg Liabilities
DTA 610.120 Trail Mountain
DTA 605.200 WY Jt Water Rd
DTA 920.150 FAS 112 Book Reserve
IFERC FORM NO.1 (ED. 12-S7)
Balance 12/31/04$ 3 601 690
894 912
150 089
552 397
166 592
654 597
32,195,111
019 000
735 878
518 181
568 025
452 603
969 918
252 773
109 924
484 249
220 116
370 066
097 436
932 767
367 272
564
833
952
938 996
507 091
137,477
(298 134)
509
759 020
214 784
423 805
267 225
126 234
Page 450.
Balance 12/31/05
165 555
660 145
964 767
160 247
975 748
812 892
515 789
243 873
616 889
252 773
561
723 026
220 116
363 219
429 391
749 905
947 073
782
174
938 996
507 091
137 477
072
759 020
616 105
131 460
415 599
496 680
116 253
101 623
861 497
355
631 392
128 665
134 346
152 298
(195 931)
443 493
227 768
569,289
459 220
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/20i2006 2005/Q4
FOOTNOTE DATA
DTA 505.115 Sales & Use Tax
DTA 425.380 Idaho Customer Balancing Account
DT A - Undistributed IRS Settlement
Total
718
715
176 616
153 786 568 142 763 126
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This ~ort Is:Date of R~ort Year/Period of Report
PacifiCorp (1) An Original (Mo, Da End of 2005/04(2) n A Resubmission 03/20/2006
CAPITAL STOCKS (Account 201 and 2)4)
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)
1 Common Stock (Account 201)750,000,000
, "
,ii'ii'
(PacifiCorp is a fully owned indirect
subsidiary of Scottish Power)
Common Stock (Mines)
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 100.00
00% Series 100.
00% Series 100.100.
40% Series 100.101.
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 2005/Q4(2) n A Resubmission 03/20/2006
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'1ares Amount ::inares ~pst Sh~res Amount(e)(f)
(g)
(h)(i)
347,158,187 308,223,674
001 001
347 161 188 308 226,675
126,243 624 300
065 206 500
18,046 804 600
930 593,000
908 190,800
65,959 595 900
69,890 989 000
592 459,200
414 633 41,463 300
FERC FORM NO.1 (ED. 12-88)Page 251
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 20051Q4
FOOTNOTE DATA
Column: d
Oregon Public Utility Commission, Docket No. UF-4193(1), Order No. 05-769, dated June 7, 2005.
Washington Utilities and Transportation Commission, Docket No. UE-050555 Order No. 1 , dated May 11 2005.
Idaho Public Utilities Commission, Case No. P AC-05-4, Order No. 29786, dated May 17, 2005.
During 2005, PacifiCorp received an increase in authority from the Oregon Public Utility Commission, Washington Utilities and
Transportation Commission and the Idaho Public Utilities Commission to issue new common stock to its immediate corporate parent
PHI by 14 851 485 shares.
As of December 31 200564 851,485 shares authorized; 15 017 902 available.
IFERC FORM NO.(ED. 12-S7) Page 450.
Blank Page
(Next Page is: 253)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmisslon 03/20/2006
OTHER 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.
fir rw)unt
Account 211 Miscellaneous Paid-in Capital
Additional Paid-in Capital
",,,
TOTAL 973,218
FERC FORM NO.1 (ED. 12-87)Page 253
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
!schedule Page: 253 Line No.Column: b
This represents the fair value of stock options granted by ScottishPower for which certain performance measures were met in March
2005. These options became fully vested in May 2005. Prior year balance of$59 808 was a June 2004 dividend that is now reflected
as return of capital instead of a capital contribution.
IFERC FORM NO.1 (ED. 12-S7) Page 450.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) 0 A Resubmission 03/20/2006
CAPITAL STOCK EXPENSE (Accoun 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.
I Line Glass ana :series of ::itocK Balance at Ena Of Year
No.(a)(b)
1 Common Stock
(:"::/":':""
Preferred Stock:
00% Serial 98,049
5 4.52% Serial 676
6 4.72% Serial 349
7 4.56% Serial 071
22 TOTAL 41,286,207
FERC FORM NO.1 (ED. 12-87)Page 254b
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da. Yr)
PacifiCorp . (2) A Resubmission
/ /
2005/04
FOOTNOTE DATA
ISchedu/e Page: 254 Line No.Column: b
Increase of $7 123 ftom rior year was due to costs incurred related to 2005 ca ital contributions.
chedule Page: 254 Line No.Column: b
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) CIA Resubmission 03/20/2006
LONG-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)
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 48,972 000
978% Series due October 1 , 2011 422 000
900% Series due November 15, 2011 500,000,000 567,009
735,000 D
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
950% Series due August 15, 2014 200,000,000 438 492
728,000 D
734% Series due October 1 , 2014 28,218 000
294% Series due October 1 , 2015 46,946,000
635% Series due October 1 , 2016 750,000
470% Series due October 1 , 2017 609 000
700% Series due November 15, 2031 300,000 000 874 150
864,000 D
900% Series due August 15, 2034 200,000 000 888,492
722 000 D
~~~~~,
~lttiJill'1e 15~.?9?~,.
.!,
i..
)" "
300,000 000 911,761
1 ,080,000 D
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 33,788
36% Series E Medium-Term Notes due Oct. 17 2005 000,000 33,788
TOTAL 319 986,000 56,346,093
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 2005/Q4
(2) EjA Resubmission 03/20/2006
LON 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 LineNominal 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)
04/01/1993 04/01/2005 04/01/1993 04/01/2005 531 250
11/06/1998 11/01/2006 11/06/1998 11/01/2006 200,000,000 11,300,000
09/15/2003 09/15/2008 09/15/2003 09/15/2008 200,000 000 600,000
04/15/1992 10/01/2010 04/15/1992 10/01/2010 20,404 000 885 809
04/15/1992 10/01/2011 04/15/1992 10/01/2011 049,000 178,966
11/15/2001 11/15/2011 11/15/2001 11/15/2011 500,000 000 500 000
04/15/1992 10/01/2012 04/15/1992 10/01/2012 10,375,000 948 350
04/15/1992 10/01/2013 04/15/1992 10/01/2013 317 000 871 211
09/15/2003 09/15/2013 11/15/2001 09/15/2013 200,000,000 10,900 000
08/24/2004 08/15/2014 08/24/2004 08/15/2014 200 000 000 900,000
04/15/1992 10/01/2014 04/15/1992 10/01/2014 294 000 591 357
04/15/1992 10/01/2015 04/15/1992 10/01/2015 29,940,000 600 231
04/15/1992 10/01/2016 04/15/1992 10/01/2016 12,695,000 140,122
04/15/1992 10/0112017 04/15/1992 10/01/2017 756 000 206 361
11/15/2001 11/15/2031 11/15/2001 11/15/2031 300 000 000 23,100,000
08/24/2004 08/15/2034 08/24/2004 08/15/2034 200,000 000 725,000
06/13/2005 06/15/2035 06/13/2005 06/15/2035 300,000,000 618 750
01/22/1993 01/24/2005 01/22/1993 01/24/2005 747
01/22/1993 01/24/2005 01/22/1993 01/24/2005 867
10/15/1992 10/17/2005 10/15/1992 10/17/2005 291,561
10/15/1992 10/17/2005 10/15/1992 10/17/2005 292 355
052 276 242 237 603 134
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 2005/04(2) nA Resubmission 03/20/2006
L )NG- 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)
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 100,000,000 267 428
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 500,000 412
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 Jul. 15 2009 125 000 000 976,904
451 250 D
15% Series C Medium-Term Notes due Aug. 9, 2011 000,000 75,327
95% Series C Medium-Term Notes due Sept. 1, 2011 25,000,000 175,398
95% Series C Medium-Term Notes due Sept. 1, 2011 20,000,000 132 118
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
25% Series C Medium-Term Notes due Feb. 1 2012 000,000 946
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 000,000 400
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 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 000 000 438,238
11% Series E Medium-Term Notes due Sept. 9, 2022 000,000 105,177
05% Series E Medium-Term Notes due Sept. 14, 2022 10,000,000 87,648
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
TOTAL 319,986,000 346,093
FERC FORM NO.1 (ED. 12-96)Page 256.
Name of Respondent This 7!Jort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) Fi A Resubmission 03/20/2006
LONG-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 ye~r, (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 ul!tstan~Jln LineNominal Date Date of (Total amount outstan ing without Interest for Year No.of Issue Maturity Date From Date To reduction for amounts lield by Amount(d)(e)(f)
(g)
reSP?~dent)
(i)
01/2211996 01/15/2006 01/2211996 01/15/2006 100 000 000 120,000
01/10/1992 01/10/2007 01/10/1992 01/10/2007 724 000 439,031
06/09/1995 06/01/2007 06/09/1995 06/01/2007 100,000,000 625,000
09/11/1992 09/11/2007 09/11/1992 09/11/2007 000,000 148 600
09/18/1992 09/18/2007 09/18/1992 09/18/2007 500,000 180,500
09/22/1992 09/24/2007 09/2211992 09/24/2007 000,000 290,800
05/12/1998 05115/2008 05/12/1998 05/15/2008 200 000,000 750 000
07/15/1997 07/15/2009 07/15/1997 07/15/2009 125 000 000 750 000
08/09/1991 08/09/2011 08/09/1991 08/09/2011 000,000 732,000
08/16/1991 09/01/2011 08/16/1991 09/01/2011 000,000 237 500
08/16/1991 09/01/2011 08/16/1991 09/01/2011 20,000,000 790 000
08/16/1991 09/01/2011 08/16/1991 09/01/2011 20,000,000 784,000
12/31/1991 12/30/2011 12/31/1991 12/30/2011 000 000 248 700
01/09/1992 01/10/2012 01/09/1992 01/10/2012 000,000 600
01/10/1992 01/10/2012 01/10/1992 01/10/2012 000 000 165,600
01/15/1992 02/01/2012 01/15/1992 02/01/2012 000,000 247,500
01/20/1993 01/22/2013 01/20/1993 01/22/2013 10,000,000 813,000
12/16/1991 12/16/2021 12/16/1991 12/16/2021 000,000 279,500
12/31/1991 12/31/2021 12/31/1991 12/31/2021 000,000 418 750
01/08/1992 01/07/2022 01/08/1992 01/07/2022 000,000 413,000
01/09/1992 01/10/2022 01/09/1992 01/10/2022 000,000 330,800
09/18/1992 09/01/2022 09/18/1992 09/01/2022 15,000 000 207 500
09/09/1992 09/09/2022 09/09/1992 09/09/2022 000,000 645 600
09/11/1992 09/09/2022 09/11/1992 09/09/2022 000 000 060,000
09/11/1992 09/09/2022 09/11/1992 09/09/2022 12,000,000 973,200
09/14/1992 09/14/2022 09/14/1992 09/14/2022 10,000 000 805 000
10/15/1992 10/14/2022 10/15/1992 10/14/2022 26,000,000 100 800
10/15/1992 10/14/2022 10/15/1992 10/14/2022 000 000 020 000
01/20/1993 01/20/2023 01/20/1993 01/20/2023 000,000 411,500
052 276 242 237 603 134
FERC FORM NO.1 (ED. 12-96)Page 257.
Name of Respondent This ~rt Is:Date of Report Year/Period of Report
PaclfiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) DA Resubmission 03/20/2006
LONG-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)
23% Series E Medium-Term Notes due Jan. 20, 2023 000 000 331
81,560 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 11,000,000 100 622
23% Series F Medium-Term Notes due Aug. 16,2023 000 000 137 211
24% Series F Medium-Term Notes due Aug. 16 2023 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 000,000 300
75% Series F Medium-Term Notes due Oct. 26, 2023 000 000 152,326
75% Series F Medium-Term Notes due Oct. 26, 2023 000 000 121 861
75% Series F Medium-Term Notes due Oct. 26, 2023 12,000,000 396
71% Series G Medium-Term Notes due Jan. 15 2026 100 000 000 904 467
Subtotal - First Mortgage Bonds 521 616,000 818,707
Pollution Control Obligations - Secured by Pledged First Mortgage Bonds:
Poll Ctrl Revenue Refunding Bonds, Moffat County, CO, Series 1994 40,655,000 874,159
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 46,500,000 624,793
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 Ctri 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 17,000,000
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
TOTAL 319 986 000 56,346,093
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 2005/04(2) n A Resubmission 03/20/2006
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 Ul!tstan!lln LineNominal 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)
01/29/1993 01/20/2023 01/29/1993 01/20/2023 000,000 329,200
07/22/1993 07/21/2023 07/22/1993 07/21/2023 000,000 960,200
07/22/1993 07/21/2023 07/22/1993 07/21/2023 000,000 798 600
08/16/1993 08/16/2023 08/16/1993 08/16/2023 15,000 000 084 500
08/16/1993 08/16/2023 08/16/1993 08/16/2023 30,000 000 172 000
09/14/1993 09/14/2023 09/14/1993 09/14/2023 000,000 337 500
09/14/1993 09/14/2023 09/14/1993 09/14/2023 000,000 135,000
09/14/1993 09/14/2023 09/14/1993 09/14/2023 000 000 134,400
10/26/1993 10/26/2023 10/26/1993 10/26/2023 000 000 350,000
10/26/1993 10/26/2023 10/26/1993 10/26/2023 16,000,000 080,000
10/26/1993 10/26/2023 10/26/1993 10/26/2023 12,000,000 810,000
01/23/1996 01/15/2026 01/23/1996 01/15/2026 100,000 000 710,000
271 054 000 207 169,818
11/17/1994 05/01/2013 11/17/1994 05/01/2013 40,655 000 118,866
11/15/1993 11/01/2021 11/15/1993 11/01/2021 300 000 476,835
11/15/1993 11/01/2023 11/15/1993 11/01/2023 500,000 683 050
11/15/1993 11/01/2023 11/15/1993 11/01/2023 16,400,000 942 180
11/17/1994 11/01/2024 11/17/1994 11/01/2024 260,000 588 384
11/17/1994 11/01/2024 11/17/1994 11/01/2024 190 000 224 616
11/17/1994 11/01/2024 11/17/1994 11/01/2024 121 940 000 3,497 668
11/17/1994 11/01/2024 11/17/1994 11/01/2024 365,000 257 734
11/17/1994 11/01/2024 11/17/1994 11/01/2024 060,000 433,777
01/01/1988 01/01/2014 01/01/1988 01/01/2014 000,000 680,352
12/01/1984 12/01/2014 12/01/1984 12/01/2014 15,000,000 600,356
01/17/1991 01/01/2016 01/17/1991 01/01/2016 45,000,000 637 375
12/01/1986 12/01/2016 12/01/1986 12/01/2016 500 000 359,450
052 276,242 237 603 134
FERC FORM NO.1 (ED. 12-96)Page 257.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2005/Q4
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)(2) 0 A Resubmission 03/20/2006
LONG-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. Fumish 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
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
Principal Amount
Of Debt issued
(b)
300,000
000,000
Total expense
Premium or Discount
(c)
132 043
404 262
(a)
1 Environ. Imprvmnt Rev Bonds, Converse County, WY, Series 1995
2 Environ. Imprvmnt Rev Bonds, Lincoln County, WY, Series 1995
Pollution Control Revenue Bonds:
6 ~9it~tii~;~~fjl)mQtA9Ji~;\'~AAtW:~r~~;~~!:1:s,~t~'~~i~~!lli;'\~;t;j;;c
;;!;':'
;c,
" ,
10~j:;!;ip!!;fr,
:,,: ,';j
7R.~Ni~~i#~~;j~w~~;I8\~j(tfiEf~nWit.f'~~\1!~Q:i~i!i.
~~,
0;~;i:jf;t~ii~~~~l;:~'i;;'i;'
." ,
8 i:i~ey!~~~ijj~~~~i~!!!f~~~lfu'lf!.It~~tie$:'j~~;:!f":'
;;;. '
: t";i..~'l"0J'
:'
Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988B
10 Poll Ctrl Rev Refndng Bonds, Sweetwater County, WY, Ser. 1990A
11 Poll Ctri Rev Refunding Bonds, Emery County, UT, Series 1991
12 Poll Ctrl Rev Refndng Bonds, Sweetwater Cnty, WY, Ser. 1988A
13 Poll Ctrl Rev Refndng Bonds, City of Forsyth, MT, Series 1988
14 Poll Ctrl Rev Refndng Bonds, City of Gillette, WY, Ser. 1988
15 Environ. Imprvmnt Rev Bonds, Sweetwater County, WY, Series 1995
16 6.150% Emery County, Utah, Series due September 1, 2030
19 Subtotal - Pollution Control Revenue Bonds
21 Construction Fund on Deposit with Trustee
23 TOTAL ACCOUNT 221
26 Reacquired Bonds: (Account 222)
29 Advances from Associated Companies: (Account 223)
335 000
305 000
22,485,000
500,000
70,000 000
45,000,000
50,000,000
45,000,000
200 000
400 000
675,000
167 524
151 908
242 163
240,792
660,750
872 505
422,443
380,198
351,905
225 000
556,549
178,464 D
738,370,000 855,040
259,986,000 55,673,747
33 TOTAL 319,986 000 56,346 093
FERC FORM NO.1 (ED. 12-96)Page 256.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PaclfiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) Fi A Resubmission 03/20/2006
LONG-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 Ol.!tstan!lln LineNominal 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)
11/17/1995 11/01/2025 11/17/1995 11/01/2025 300,000 224 251
11/17/1995 11/01/2025 11/17/1995 11/01/2025 000 000 950 332
09/29/1992 12/01/2020 09/29/1992 12/01/2020 335 000 269 353
09/29/1992 12/01/2020 09/29/1992 12/01/2020 305,000 181 925
09/29/1992 12/01/2020 09/29/1992 12/01/2020 485,000 648 783
01/01/1988 01/01/2014 01/01/1988 01/01/2014 500,000 402 712
07/25/1990 07/01/2015 07/25/1990 07/01/2015 70,000 000 503,851
OS/23/1991 07/01/2015 OS/23/1991 07/01/2015 45,000,000 653,117
01/01/1988 01/01/2017 01/01/1988 01/01/2017 50,000,000 800,554
01/01/1988 01/01/2018 01/01/1988 01/01/2018 45,000 000 587 793
01/01/1988 01/01/2018 01/01/1988 01/01/2018 200,000 493,492
12/14/1995 11/01/2025 12/14/1995 11/01/2025 24,400 000 868,497
09/24/1996 09/01/2030 09/24/1996 09/01/2030 12,675,000 779,513
738,370,000 26,864,816
147 758
007,276 242 234,034 634
052 276 242 237 603,134
FERC FORM NO.1 (ED. 12-96)Page 257.
Name of Respondent This '(!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/04(2) n A Resubmission 03/20/2006
LONG- 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)
1 Other Long-Term Debt: (Account 224)
.,..;;
000 000 672 346
TOTAL ACCOUNT 224 60,000,000 672 346
TOTAL 319,986,000 56,346,093
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 2005/Q4
(2) (5 A Resubmission 03/20/2006
LON .:i-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 ul!tstan?ln LineNominal Date Date of (Total amount outstan ing without Interest for Year
of Issue Maturity Date From Date To reduction for amounts field by Amount No.
(d)(e)(f)
(g)
reSP?~dent)(i)
06/11/1992 06/15/2007 07/01/2003 06/15/2007 000,000 568,500
45,000,000 568 500
052 276 242 237 603,134
FERC FORM NO.1 (ED. 12-96)Page 257.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo. Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
!schedule Page: 256 Line No.27 Column:
On June 13 2005, PacifiCorp issued $300.0 million of its 5.25% Series of First Mortgage Bonds due June 15 2035. Authorizations
for the issuance were as follows:
Oregon Public Utility Commission, Docket No. UF-4215, Order No. 05-258, dated May 9,2005.
Washington Utilities and Transportation Commission, Docket No. UE-050556, Order No., dated May 11, 2005.
Idaho Public Utilities Commission, Case No. PAC-05-5, Order No. 29787, dated May 17 2005.
ISchedule Page: 256.Line No.Column:
On March 16, 2005, PacifiCorp extended the maturity date of the PCRB series to December 1, 2020.
'Schedule Page: 256.Line No.Column:
On March 16, 2005, PacifiCorp extended the maturity date of the PCRB series to December 1 , 2020.
!schedule Page: 256.Line No.Column:
On March 16, 2005, PacifiCo extended the maturity date of the PCRB series to December 1 , 2020.
chedule Pa e: 256.Line No.Column:
As of December 31 2005, there were 450 000 shares outstanding ($100 stated value per share) on the $T.48 series subject to the
following mandatory redemption requirements: 37,500 shares are subject to mandatory redemption on June 15, 2006, with all shares
utstanding on June 15 2007 subject to mandatory redemption on that date.
!Schedule Page: 256.Line No.Column:
Authorization for the issuance of long-tenD debt ($1 000 000 000 authorized; $700 000 000 available as of December 31 , 2005) is as
follows:
Oregon Public Utility Commission, Docket No. UF-4215, Order No. 05-258, dated May 9, 2005.
Idaho Public Utilities Commission, Case No. P AC-05-, Order No. 29787, dated May 17 2005.
Authorization for the issuance of 10ng-tenn debt ($400 000 000 authorized; $100 000 000 available as of December 31, 2005) is as
follows:
Washington Utilities and Transportation Commission, Docket No. UE-050556, Order No.1 dated May 11, 2005.
Authorization for the issuance of pollution control revenue bonds ($125 000 000 authorized; $79 225 000 available as of December
2005) 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.
Blank Page
(Next Page is: 261)
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) 0 A Resubmission 03/20/2006
RECONCILIATION OF REP( RTED NET INCOME WITH TAXABLE 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 fumished on Schedule M-1 of the tax retum 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 retum, reconcile reported net income with taxable net income as if a
separate retum 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.
Year/Period of Report
End of 2005/04
Name of Respondent
PacifiCorp
Line Particulars (uetans)No. (a)
1 Net Income for the Year (Page 117)
4 Taxable Income Not Reported on Books
9 Deductions Recorded on Books Not Deducted for Return
13_",-,/""
14 Income Recorded on Books Not Included in Retum18
19 Deductions on Retum Not Charged Against Book Income
26 ptft~f
27 Federal Tax Net Income
28 Show Computation of Tax:
AITlount
(b)
856,264 225
'",X'C';'
". ;"'"
474 152,009
'/,
'i"'885,137 899
251 907 689
30 Federal Income Tax at 35.00%
31 Federal Accrual to Retum Adjustments
32 Tax Reserve Changes
33 IRS Settlement
34 Tax Reclass
35 Credits
37 Total
88,167,691
715,564
540,027
446 242
594 309
128,424
116,146,791
FERC FORM NO.1 (ED. 12-96)Page 261
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2) , A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
ISchedule Page: 261 Line No.Column:
Particulars (Details)
Contributions in Aid of Cons1ruction
Highway relocation
Regulatory assets - F AS 133
Bridger Coal Company Reclamation Trust Earnings - PMI
OR Rate Refunds
Unearned Joint Use Pole Contact Revenue
Bridger Coal Company GainlLoss on Assets Disposed
Total
!schedule Page: 261 Line No.13 Column:
Particulars (Details)
Federal/State Income Tax
Book Cost Depletion - Addback
Non Deductible Parachute Payment
Merger Transaction Costs
Mandatory Redeemable Preferred Stock - FAS 150
Meals & Entertainment
Penalties
Lobbying expenses
SP Management fee
Meals & Entertainment - Bridger Coal
PMI Fuel Tax Credit
Book Depreciation
Tax vs Book Depreciation - PMI
Capitalized Depreciation
Avoided Costs
Acquisition Adjustment Amort
AFUDC - Equity
Trojan Decomissioning Costs - Regulatory
Weatherization
Severance Accrual - Cash Basis
May 2000 Transition Plan Costs-
May 2000 Transition Plan Costs-ill
May 2000 Transition Plan Costs-
May 2000 Transition Plan Costs-
May 2000 Transition Plan Costs- WYE
May 2000 Transition Plan Costs- WYW
Glemock Excluding Reclamation-
97 Software WriteDown-
99 Software WriteDown-
Transition Team Costs-
Noell Kempf CAP - UT
P&M Strike Amortization - UT
98 Early Retirement-OR rate order
DefReg Asset-IDU DefNet Power Costs
DefReg Asset-OR DefNet Power Costs
DefReg Asset-UT DefNet Power Costs
Post Merger Loss-Reacq Debt - Addback
Chona PIt Transact Costs-APS Amort
Trail Mountain Mine Closure
I FERC FORM NO.1 (ED. 12-87)
Amount
840 216
272 280
370 160 650
826 974
498
506 704
827
453 757 149
Page 450.
Amount
185 094 105
519 072
547 866
326
903 947
746 714
194 819
877 905
263,392
203
900
393 101 445
058 953
404 421
703 635
479 353
093 228
605 572
428 093
038 540
931 492
922 745
504 605
948 138
344 716
159 014
302 399
257 182
183,511
242 952
682
299 449
676 947
812 095
344 239
872 924
849 941
938 633
203 570
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
Trail Moutain Umecovered Inventory
IDAI Costs - direct access
W A Disallowed Colstrip #3- Write-off
SB 1149-Related Regulatory Assets
SERP Accrual - Cash Basis
Reg Assets BP A balancing accounts
Trail Mountain
Min. Pension Liability Adjustment
W A state Transition Costs
TGS Buyout
Lakeview Buyout
Buffalo Settlement
Joseph Settlement
TriState Finn Wheeling
Mead Phoenix Availability &Trans Charge
Firth Cogen Settlement
Option Purchases
Herrniston Swap
Prepaid Taxes - CA Property Taxes
Prepaid Taxes - OR Property Taxes
Pollution Control Facility (Book v. Tax Amort)
Wasach workers comp reserve
Sales & Use Tax Accrual
Sec 17494-98 & 99-00 RAR
Bridger Coal Company Section 471 Adjustment - PM!
Bridger Coal Company Extraction Taxes Payable - PMI
Property Insurance( same as Injuries & Damages)
Non-ARO Liabilily - Reg Liability
Reg liability BP A balancing accounts
Reg Liab - OR Balance Consol
F AS 106 Accruals - Cash Basis
Deferred Compensation Accrual- Cash Basis
Vacation Accrual - PMI
SERP
Reg AssetslReg Liabilities - total
Min. Pension Liability Adjustment
Steam Rights Bundell Geothennal
Bad Debts Allowance - Cash Basis
Coal M&S Inventory Write-Off-Centralia
Vacation Accrual- Cash Basis (2.5 mos)
NW Power Act - W A
Trail Mountain Accrued Liabilities
Idaho Customer Balancing Account
Reverse Accrued Final Reclamation
R & E - Sec.174 Deduction
PMI Devt Cost Amort
PMI Overburden Removal
Bear River Settlement Agreement
Tenant Lease Allow - PSU Call Cntr
Long-term Incentive Plan
Deferred Shares
Executive Stock Option Plan
Total
IFERC FORM NO.(ED. 12-S7)
304 104
333 105
188
873 061
015 291
208 197
600 163
851 000
590 224
15,474
43,280
118
137 381
706 320
377 760
444 080
360 000
539 573
405 615
357 109
327 196
772
133,639
202 619
120
438 709
678 068
703 323
703 133
433 747
866 387
496 533
071
105 612
397,777
074 000
109 739
205 950
121
759 297
131 911
629 169
345 139
397 825
198 493
302 868
580 741
353 996
401 300
809 986
150 000
973 218
856 264 225
Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 1(2) . A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
ISchedule Page: 261 Line No.18 Column:
Particulars (Details)
Tax Exempt Interest ( No AMT)
Utah Deferred Comp / COLI
Gain / (Loss) on Prop. Disposition
Centralia Gain Give Back - OR
F AS 133 Derivatives
Oregon Share of Hermiston
Oregon Gain on Sale
W A Rate Refunds
F AS 133 Derivatives - Book Umealized Gain/Loss
Weather Derivatives
Aqualia Weather Hedge
Centralia Give Back-W A
SMUD Revenue Imputation-UT reg liab
Equity Earnings in Subsidiaries
Total
ISchedule Page: 261 Line No.26 Column:
Particulars (Details)
Tax Percentage Depletion - Deduction
Depletion - PM!
2004 JCA - Qualified Production Activities (3%)
PPL Pre - 1943 Preferred Stock Div - Deduction
Trapper Mine Dividend Deduction
SPI 404(k) Contribution
Bridger Coal Tax Exempt Interest Income
Bridger Coal Company Depletion - PM!
Tax Depreciation
Depreciation (Tax Depreciation M -1 )
30% capitalized labor costs for Powertax input
Basis Intangible Difference
AFUDC - Debt
ADRRepair Allowance 3115
Coal Mine Development
Coal Mine Extension
Removal Cost (net of salvage)
Ptax NOP As
Coal Mine Development- 30% Amortization
ARO - recIass to reg assets/liability & ARO liability
Chona SHL (Tax Int. - Tax Rent)
Malin SHL (Tax Int. - Tax Rent + Book Dep )
Min. Pension Liability Adjustment
Pension / Retirement Accrual - Cash Basis
Y2K Expense-
Environmental Clean-up Accrual
Deferred Intervener Funding Grants
ARO Reg Assets
Contra-reg assets - transition plan
Income Tax Audit Payment
781 Shopping Incentive
SB 1149 Costs
--.J
Amount
402
650 921
567 774
708 548
135 726,234
181
289 084
861
277 230 384
017 189
469,027
197 003
430,832
838 569
474 152 009
Amount
299 869
124 797
992 598
390 517
331 977
109 475
369 435
485 421
612 294 582
537 205
593 114
601 932
621 500
100 000
014 797
484 941
970,269
247 448
608 889
703,323
215 436
303 285
430 637
295 409
348
777 076
170 753
981 605
403,406
512 123
151 321
173 793
IFERC FORM NO.1 (ED. 12-S7) 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 03/20/2006 2005/Q4
FOOTNOTE DATA
Prepaid Taxes - OR PUC
Prepaid Taxes - UT PUC
Prepaid Taxes - ill PUC
PrepIDd Ta~s - VVY PSC
VVY Joint Water Board Reserve - Deduction
Prepaid Insurance -IBEW 157 contingency reserve
BCC Roll NOP As 99-00 RAR
Roll (Not Ptax) 99-00 RAR
Bonus Liability - Electric - Cash Basis (2.5 mos)
OCI
U of VVY Contract Amort - Prepaid
DefReg Asset-Transmission Srvc Deposit
Injuries and Damages Accrual - Cash Basis
DefReg Asset-Foote Creek Contract
Redding Contract - Prepaid
Distribution O&M Amort of Write off
Amort of Debt Disc & Exp
Purchase Card Trans Povision
Misc. Current and Accrued Liability
Defer MagCorp Revenues
Centralia Sale
Bogus Creek Settlement
Special Assessment - DOE
Extraction Tax Accruals - Cash Basis (8.5 mos)
Interest Accual on FIT - Cash Basis
Merger Credits - OR
Merger Credits - W A
Amort of Projects-Klamath Engineering
Umpqua Settlement Agreement
Sec. 263A Inventory Change - PMI
State Tax Deductions
Total
499 467
931
146
993
300 000
516 272
102 640
733 950
592 919
599 975
732
620 350
272 607
137 640
549 996
215 978
275
042
660 220
481 836
489 348
118 000
625
173 782
468 949
157 505
565 684
423
171 317
209 491
980 525
885 137 899
IFERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 262)
Name of Respondent This i!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) (j A Resubmission 03/20/2006
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 ~1~xes ~:rcr Adjust-C argedNo.(See instruction 5). axes Accru~!J ~repala axes ~nng ~ring ments(Account 236)(Include In Account 165)ear ear(a)(b)(c)(d)(e)(f)
Federal:
Income 948,540 116,146,791 , 135
FICA 900,378 900,378
Unemployment 834 334 944 362 942
Unemployment - Energy 705 250 703 195,608
Unemployment - Interwest 399 069 827
Excise Tax - Coal 130,823 878,487 776 844
8 Subtotal 106,553 948 540 153,514 372 111 373,555 10,827,441
State:
Subtotal
Arizona:
Property 959,828 904 916 912 286
Income 130,583 109,454 131 550
Subtotal 829 245 014,370 043,836 82,940
Califomia:
Property 603 308 603,308
Unemployment 732 595
Bank/Corp. -
Franchise-Income 616,633 240 798 289,410
Use 238 128 011 123,952
Local Franchise 567 983 865,006 795,810
Subtotal 191,854 909 855 876,075 173 332
Colorado:
Property 500 000 959 894 229,894
Income 105,541 65,672 78,930 i:'
.."
Subtotal 394 459 025,566 308,824 764
Idaho:
Property 1 ,672,092 817 828 766 311
Income 811 864 525 378 631 441
':/",," .
398;~1=?'
KWh 500 834 834
Unemployment 336 36,735 /T::'
Use 16,581 95,454 110 210
Subtotal 501,037 498,830 567 531 397 512
TOTAL 604 016 692 288 270,816 144 230,171,010 929,826
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 2005/Q4
(2) Fi A Resubmission 03/20/2006
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 Ket.Other No.ACCO
~m 236)
(Incl. in Account 165)(Account 408.1 , 409.(Account 409.Earnings (Account 439)
(h)(i)(k)(I)
123 864 95,781 130 ~;~;fi~t
322,764
390
633
232 466 -'i
528,611 781 130 733,242
952,458 904 916
69,739 86,763
882 719 991 679 22,691
579 961
, .
750,490 190,877 8W-
-."
92;!
11,297 ~~1
637 179 865,006
398,966 635,844 274 011
230,000 959,275 ,..",1
035 057
160 965 011 332 234
723 609 815,728
103 914 416 459
500 834
""':~'.:
\31;336:f--825
829,848 f--255 021 243,809
310,489 683,453 199,956 778 859,366
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 2005/Q4(2) n A Resubmission 03/20/2006
TAXES ACCRUED, PREPAID AND CHA 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.
Kind ofTax BALANCE AT BEGINNING OF YEAR c1~xes d Parff Adjust-argeNo.(See instruction 5)"(axes Accru~!1 F'repatd Taxes ~rmg ~ring ments(Account 236)(Include m Account 165)ear ear(a)(b)(c)(d)(e)(f)
3 Montana:
Property 141 106 337 201 311 999
Corporate License-Income 177,358 563 105,240
Energy License 751 248,113 243,281
Wholesale Energy 38,648 172,281 168,797
8 Subtotal 058 147 845,158 829,317 352
Nevada:
Unemployment
Other Payroll Taxes 346 346
Subtotal 415 415
New Mexico:
Property 751 067 284
Subtotal 751 067 284
Oregon:
Property 573 347 362 772 15,275 847
Unemployment 358,458 "322
Wilsonville Payroll 170 694
Excise-Income 793,353 750,293 709 280
City of Portland-Income 129,516 563 105,240
Office of Energy 170,401 367,433 394,063
Tri-Met 109,548 877 572
Franchise 526 300 16,852 077 612,680
Subtotal 11,449,169 743,748 890 314 298,572 104 302
Texas:
Unemployment 673 673
Subtotal 673 673
Utah:
Property 324 779 369,420 456,739
Income 210,163 071,679 893,668
Unemployment 462 410 451 961
Navajo Nation 616 616
Use 235,325 159,496 082,494
Interwest Mining Use 724 724
TOTAL 604 016 692 288 270,816,144 230,171,010 929 826
FERC FORM NO.1 (ED. 12-96)Page 262.
Name of Respondent This
i!Prt
Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
TAXESACC 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 Ket.Other No.
ACCO
~SJ 236)
(Incl. in Account 165)(Account 408.1, 409.(Account 409.Earnings (Account 439)
(h)(i)(k)(I)
166,308 337 201
128,683 410
60,583 248,113
132 172 281
140 340 827 005 18,153
346
346
534 067
534 067
7,486 422 15,279 752
141 030 765,485
178,191 69,409
197 031 367,433
765,697 16,852,077
15,084 918 683,453 36,334,156 556,158
673
237 460 550,402
473,553 227 558
616
312,327 'i"
310,489 683 453 199,956 778 859,366
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 2005/Q4
(2) Fi A Resubmission 03/20/2006
TAXES ACCRUED, PREPAID AND CHAt 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.
ILlne Kind of Tax BALANCE AT BEGINNING OF YEAR c1~xes d ~~cf Adjust-argeNo.(See instruction 5)1axes Accruli!fI F'repai,d Taxes ~nng ~ring ments(Account 236)(Include In Account 165)ear ear(a)(b)(c)(d)(e)(f)
Gross Receipts 047 483 915 952 3,487 261
2 Subtotal 818,474 984 573 378 463 074 930
4 Washington:
Property 499,980 3,467,041 3,448,186
Unemployment 103,776 100,629
?;:'
Business Occupation 892 171 202
Public Utility 801,875 664 751 - 7 927 789
Use 113 180,961 68,245
Retailing 233 233
Subtotal 308,105 078,011 427 794 147
Washington D.
Unemployment 486 486
Subtotal 486 486
Wyoming:
Property 3,484 576 018 237 013,345
Property - Glenrock 238 116 047 115 261
Unemployment 89,359 87,349
Other Payroll Taxes 286 286
Glenrock Sales & Use 844 084 28,928
Franchise 154,000 184 301 166,401
Use 4,485 367,638 278 971
Annual Report 32,431 431
Subtotal 701 143 836,383 722 972 010
Miscellaneous:
Goshute Possessory 612 337 26,949
She-Ban Possessory 132 712 132,712
Navajo Possessory 15,408 31,818 317
Ute Possessory 10,103 103
Crow Possessory 059 51,254 49,686
Umatilla 857 46,857
Misc. Sales & Use Tax Provo 180,000 783 816 -46 360
Miscellaneous Other Taxes 12,773 773
Subtotal 241 079 208,071 333,213 -46 360
TOTAL 604,016 692,288 270,816,144 230,171 010 929 826
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 2005/Q4(2) Fi A Resubmission 03/20/2006
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 AdJus~ents to Re!.Other No.ACCO
~BJ 236)
(Incl. in Account 165)(Account 408., 409.(Account 409.Earnings (Account 439)
(h)(i)
(j)
(k)(I)
476,174 915,952
499,514 35,699 528 285,045
518,835 341,825
077 23,171
538,837 664,751
104 603
233
955,175 029 980 48,031
486
3,489,468 886 591
024
286
171 900 184,301
152 I""
:?'
431
812 544 103,609 1 ,732 774
337
132 712
15,909 818
10,103
627 51,254
46,857
041
577 278,081 010
310,489 683 453 199 956,778 859,366
FERC FORM NO.1 (ED. 12-96)Page 263.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
Line No.
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 03/20/2006 2005/04
FOOTNOTE DATA
Amount
$35 452
568
$83 020
Amount
$14 400
608 118
196 500
819 018
Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PaclfiCorp I (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
Line No.Column: I
Account
Taxes applicable to Other Income & Deductions - 408.2 & 409.
Distribution Rent Expense, Rents - 589
Total
Amount
$122 492
724
$125 216
Amount
$240
116 046
360
$131 646
Line No.Column: I
IFERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 266)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PaciflCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
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
nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g). Include in column (i)
the average period over which the tax credits are amortized.
Account
No.SUbd
l~~sions
of Year Deferred for Year Current Year s Income Adjustments(b) ACCOUQt NO. Amount f\CCOUQII'IO. f\mOum
( )
(c) (d) (e) (f)
1 Electric Utility
23%
34%
47%
510%73,403,191 411.4 789,42~
. ,.,.
~1'5i4-.16.482:
7 Idaho 039 637 411.65,43E
8 TOTAL 442,828 854,86C 15,416,482
9 Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
10%085,352 420 065,26C
Total Nonutility 085,352 065 26C 15,416 482
FERC FORM NO.1 (ED. 12-89)Page 266
Name of Respondent This 'f!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/04
(2) Fi A Resubmission 03/20/2006
ACCUMULATED D :FERRED INVESTMENT TAX CRED TS (Account 255) (continued)
,,_.
ADJUSTMENT EXPLANATION Lineof Year of AI ocatlon No.to Income
52,197 285
974 201
171 486
436,574
16,436 574
FERC FORM NO.1 (ED. 12-89)Page 267
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
Page 450.I FERC FORM NO.1 (ED. 12-87)
Blank Page
(Next Page is: 269)
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PaclfiCorp (1) An Original (Mo, Da, Yr)End of 2005/04(2) 0 A Resubmission 03/20/2006
0 HER DEFFERED CREDITS (Account 253)
1. Report below the particulars (details) called for conceming '?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)
Cogeneration Bonds - Sunnyside 413,417 413 417
Working Capital Deposit DG& T 159 688 143 329 159 359
Working Capital and Coal Pile
Deposits from Provo City 273 000 273,000
Working capital deposit from UAMPS 029,000 143 596 000 433,000
Reclamation Costs - Trapper Mine 193 749 339 851 533,600
Reclamation Costs - Deseret Mine 750,825 151 128 744 697
Reclamation Costs - Trail
Mountain Mine 146,738 146,738
Deferred Compensation - PPL 288,973 131 047 820 241 153
Transmission Service Deposit 889,326 131 326 228 563,098
Def. Credits - Pricing Dispute 904 903
';'
:Vanous:;'932 405 972,498
MCI F.G. wire lease 558,898 278,705 837 603
Firth Cogeneration Buyout 349,080 131 349,080
Redding Contract 050,056 456 549,996 500,060
Foote Creek Contract 393,502 137 640 255 862
Lakeview Buyout 55,000 131 55,000
Environmental Liabilities -
Centralia Plant 116,151 367 791 483,942
Environmental Liabilities -
Centralia Mine 114,123 431 735 53,190 160,578
Stock Incentive Plan - 2001 53,971 123 971
Stock Incentive Plan - 2002 125 132 123 125 132
Wyoming Joint Powers Water
Board Settlement 575,000 131 300,000 275,000
Compensation Reduction 512 138 916 836 10,428 974
TOTAL 618 828 555 249 528,412 61,591 991
FERC FORM NO.1 (ED. 12-94)Page 269
Name of Respondent This 'i!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) 0 A Resubmission 03/20/2006
0 HER DEFFERED CREDITS (Account 253)
1. Report below the particulars (details) called for concemlng '?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)
Uneamed Joint Use Pole Contract 843,664 454.084 211 759,453
Oregon DSM Loans NPV Uneamed 381,419 456.363,596 017 823
Exec Trust Comp Reduction Plan -
SPI Stock 053 523 016 415 069,938
Miscellaneous Security Deposits 600 232 300 300
Environmental Liabilities -
Non-Current 386,952 620,678 766,274
Deseret Power Security Deposits 511 328 511 328
Deferred Revenue -
Lease Incentives 421 151 421 151
Other Deferred Credits - C& T 623 145 623 145
TOTAL 58,618 828 555,249 528,412 591 991
FERC FORM NO.1 (ED. 12-94)Page 269.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
chedu/e Pa e: 269 Line No.: 21 Column:
Account 456.
Account 447
chedule Pa e: 269 Line No.Column:
Account 456
Account 142
Schedu/e Pa e: 269.Line No.Column:
Account 580
Account 598
I FERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 272)
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmisslon 03/20/2006
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.
Name of Respondent
PaclfiCorp
Year/Period of Report
End of 2005/Q4
Line
No.
CHANGES DURING YEAR
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
5 Other (provide details in footnote):
968 777 334 292
8 TOTAL Electric (Enter Total of lines 3 thru 7)
9 Gas
10 Defense Facilities
968,777 334 292
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 ofTOTAL
19 Federal Income Tax
20 State Income Tax
968,777 334,292
852 881
115,896
294,301
991
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 2005/04(2) A Resubmission 03/20/2006
ACCUMULATED DEFERRED INCa E TAXES ACCELERATED AMORT ZATION PROPERTY (Account 281) (Continued)
3. Use footnotes as required.
Name of Respondent
PaclfiCorp
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
Amount
Balance at
End of Year
Line
No.
Debits
634 485
634 485
634 485
558 580
75,905
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 273
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 03/20/2006
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.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2005/Q4
Line
No.
CHANGES DURING YEAR
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
3 Gas
4 FAS 109
5 TOTAL (Enter Total of lines 2 thru 4)
6 Nonutility
1,470 301 545 304 625 511 266,542,739
500,987 500
971 289,045
502,247
304 625 511 266,542 739
9 TOTAL Account 282 (Enter Total of lines 5 thru
10 Classification of TOTAL
11 Federal Income Tax
12 State Income Tax
13 Local Income Tax
978,791,292 304,625 511 266,542,739
742,066,326 268,183,788 234,656,780
236 724 966 36,441 723 885,959
NOTES
FERC FORM NO.1 (ED. 12-96)Page 274
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 03/20/2006
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 2005/Q4
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.to Account 411.
ADJUSTMENTS
Amount
Balance at
End of Year
Line
No.
Debits
887 281
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 03/20/2006
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 2005/04
(a)
Balance at
Beginning of Year
(b)
LIne
No.
Account
1 Account 283
2 Electric
3 Regulatory Assets
4 FAS 133 Derivatives
5 PMI Deferred Liabilities 119 804
823,313
669,684
115,483,481 436,214
8 Other
9 TOTAL Electric (Total of lines 3 thru 8)
10 Gas
17 TOTAL Gas (Total oflines 11 thru 16)
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)
20 Classification of TOTAL
360,308 673 150,172,981 248 663,232
317,204 550 134,103,859 218,275,167
43,104,123 069,122 30,388,065
21 Federal Income Tax
22 State Income Tax
23 Local Income Tax
NOTES
FERC FORM NO.1 (ED. 12-96)Page 276
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 03/20/2006
ACCUMULATED EFERRED INCOME TAXES - OTHE (Account 283) (Continue)
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.
Year/Period of Report
End of 2005/Q4
Amounts Credited
to Account 411.
ADJUSTMENTS
Balance at
End of Year
(k)
Line
No.
190
219
219
190
855,336 190,282
206 314219
20,656,971
53,317,456
19,938,119
1 ,232 760
162 604,656
400 396
167 897 026
26,061 650 95,145,306 330 902,078
26,061 650 95,145 306 330 902 078
480,610 83,763,269 291,315,901
581 040 382,037 39,586 177
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 277
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
ISchedule Page: 276 Line No.
Account
DTL 205.100 Coal Pile Inventory Adjustm
DTL 425.250 TGS Buyout
DTL 425.260 Lakeview Buyout
DTL 425.270 Buffalo Settlement
DTL425.280 Joseph Settlement
DTL 425.290 TriState Finn Wheeling
DTL425.300 Mead Phoenix Availability&T
DTL 425.340 Firth Cogen Settlement
DTL 425.350 Option Purchases
DTL 425.360 Henniston Swap
DTL 210.100 Prepaid Taxes - OR PUC
DTL 210.120 Prepaid Taxes - UT PUC
DTL 210.130 Prepaid Taxes - ill PUC
DTL 210.140 Prepaid Taxes - WY PSC
DTL 210.150 Prepaid Taxes - CA Property
DTL210.160 Prepaid Taxes - OR Property
DTL 330.100 PollutionControlFacility(Bk
DTL 605.200 WY Joint Water Board Reserv
DTL 730.110 FAS 133 Derivatives
DTL 740.100 Post Merger Loss-Reacq Debt
DTL 720.600 FAS115 Mark to Mark Accrual
DTL 415.637 Min. Pension Liability Adju
DTL 320.210 R & E - Sec.174 Deduction
DTL 920.120 Investment in SPI
DTL 705.190 Oregon Share of Henniston
DTL 205.200 Coal M&S Inventory Write-
DTL 730.150 Weather Derivatives
DTL 425.380 Idaho Customer Balancing Ac
DTL 605.710 Reverse Accrued Final Recla
DTL Flowthrough Partnership Income
DTL 730.180 Aquila Weather Hedge
DTL 610.150N NOPA 98 99-00 RAR
DTL 610.06SN NOPA 11999-00 RAR
DTL610.00SN SEC 17494-98 & 99-00 RAR
DTL 610.095 N Roll (not Ptax) 99-00 RAR
DTL 505.115 Sales & Use Tax Accrual
DTL 105.4143/165 Basis Diff-Intangibles
DTL210.200 Prepaid Property Taxes
DTL 425.320 Umpqua Settlement Agreement
DTL 720.900 Min SERP Liab OCI
Total Other Deferred Laibilities
Column:
Balance at Amounts Amounts Adjustments
Begmning Debited to Credited to Balance at
of Year Account 410.1 Account 411.1 Account 219 End of Year
291,146 168,791 459,937
979 872 107
79,387 425 62,962
11,430 11,430
721,234 52,138 669 096
268,056 268,056
188,533 143,364 045,169
294 932 168,533 126,399
136,624 136,624
525,537 204,774 320,763
903,082 189 558 195,930 896 710
277 290 353 277,643
23,786 369 29,155
007 793 85,800
153,935 153 935
572,801 135,527 1,437,274
271,415 124,178 147,237
(683,118)683,118
993 331 78,244 663 735,126 502,868
15,398,683 220,117 13,178,566
345,866 557,407 903 273
590 624 603,193 515,905 (3,530,961)146,951
15,760,702 460 668 004 16,146,366
510,081 364,880 874 961
015 141 73,156
561,305 272,282 833 587
339 37,339
256 128,728 130,984
13,218,937 150,946 13,067 991
058,884 058,884
104 573 15,518,976 924 710 698 839
17,427 17,427
877 041 877 041
12,124,544 \2,124 544
283 152 283,152
50,718 50,718
367,005 15,918 351 087
712,590 712 590
017 65,017
298 135 298,135
92.823.313 115.483.481 37436214 (2.973.554)167.897.026
IFERC FORM NO.1 (ED. 12-87)Page 450.
Blank Page
(Next Page is: 278)
Name of Respondent This '(!Jort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) CIA Resubmission 03/20/2006
0 HER REGULATORY LIABILITIES (Account 254)
1. Report below the particulars (details) called for conCE1rning 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 QuarterlYear ~ccoum Amount Credits QuarterlY earCredited
(a)(b)(c)(d)(e)(f)
FAS 109 Regulatory Liability 859,230 157,271 28,701,959
Centralia Gain Giveback 24,573,971 456,431 24,573,971
OR Gain on Sale of Assets to EPUD 116,855 984 126,839
Property Insurance Reserve 024,038 924 2.472.427 551 611
OR UE134 Power Cost 885,080 885,080
6 SMUD Revenue Imputation 35,270,527 440, 442 710,562 344,923 32,904 888
7 Oregon Rate Refund 251 659 377 79,969
Utah Home Energy Lifeline 395 138 138 898 743,760
9 BPA Washington Balancing Account 060,971 440, 442 077.412 402,824 386,383
BPA Oregon Balancing Account 10,259,724 440, 442 173,301 877,098 13,963,521
BPA Idaho Balancing Account 440, 442 348,192 970 436 622,244
ARO/Reg Dill - Deer Creek Mine Reclamation 334 604 230,501 208,228 268,024 394,400
ARO/Reg Diff - Trojan Nuclear Plant 031 370 230, 403 84,062 947,308
Reg Liability. WA Rate Refund 359,510 359,510
FAS 109 - WA Flow Through 13,515 318 190,410 555,873 12,959,445
Reg Liability - OR Balance Consolidation 560,027 182.839,857 579,422 299,592
Washington Low Income Program 440 827 435 973.499 146,064
FAS 133 - Derivative Net Reg Liability
""""
247.454,086 339,750,164 92,296,078
Reg Liability. OR Consolidated 182.484,999 681,539 196,540
TOTAL 128,575,966 300,617 063 370,361,698 198,320,601
FERC FORM NO. 1/3-Q (REV 02-04)Page 278
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp I (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
chedule Pa e: 278 Line No.Column:
Account 182.3
Account 190
Account 282
chedule Page: 278 Line No.Column:
Account 440
Account 442
Account 444
Schedule Pa e: 278 Line No.Column:
Account 440
Account 442
Account 444
Account 450
Account 451
Account 454
Account 456
chedule Pa e: 278 Line No.Column:
Account 440
Account 442
Account 444
Account 445
Account 450
Account 451
Account 454
Account 456
chedule Pa e: 278 Line No.Column:
Account 440
Account 442
Account 444
Account 445
Account 450
Account 451
Account 454
Account 456
chedule Pa e: 278 Line No.Column:
Account 174
Account 1
Account 244
Account 421
Account 426
IFERC FORM NO.1 (ED. 12-S7) Page 450.
This ~ort Is: Date of Report
(1) ~ An Original (Mo, Da, Yr)
(2) A Resubmission 03/20/2006
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). Un billed 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 footnota.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2005/Q4
(a)
Operating Revenues Year
to Date Quarterly/Annual
(b)
Operating Revenues
Previous year (no Quarterly)
Line
No.
Title of Account
1 Sales of Electricity
2 (440) Residential Sales
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See Instr. 4)
5 Large (or Ind.) (See Instr. 4)
6 (444) Public Street and Highway Lighting
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales
10 TOTAL Sales to Ultimate Consumers
858,409,269
775 094 563
17,038,050
353,876
812 631 284
748,767 664
037 366
19,703,361
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
139
502,422 975
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
535,245
681 519
323,072
691 582
170,132
712,13229,072,161
143 884 805 130,295 327
26 TOTAL Other Operating Revenues
27 TOTAL Electric Operating Revenues
186 173 730 159,192 245
989 584,939
FERC FORM NO.1 (ED. 12-96)Page 300
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 03/20/2006
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) regulariy u$ed by the
respondent if such basis of dassification 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 un billed revenue by accounts.
8. Include unmetered sales. Provide details of such Sales in a footnote.
Year/Period of Report
End of 2005/Q4
MEGAWATT HOURS SOLD
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)(d) (e)
AVG.NO. CUSTOMERS PER MONTH
Current Year (no Quarterly)
(f)
Line
No.
14,768 597 14,475,929 194,933 190 812
601 466 19,454 708 34,235 485
165 692 160,911 271 368
460,326 537 007
646,202 816 147 613,112 578 247
274 441 13,356 980
62,920 643 62,173,127 613 112 578,247
920,643 173 127 613 112 578 247
Line 12, column (b) includes $
Line 12, column (d) includes
12,034 000
142 108
of unbilled revenues.
MWH relating to unbilled revenues
FERC FORM NO.1 (ED. 12-96)Page 301
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
~chedule Page: 300 Line No.11 Column:
In July 2003, the Emerging Issues Task Force ("EITI") 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 ofEITI 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 (flISt
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 l2-month period ending March 31, 2004 as opposed to just the
3-month 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 ofEITF No. 03-
had no impact on PacifiCorp s Net income.
FY 2004 Total
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)
Page 300 Page 304 Variance
Twelve Months Twelve Months Twelve Months
Ending Ending Ending
December 31 ,December 31 December 31,
2005 2005 2005
968,845,322 968,845,322
858,409,269 858,409,269
775,094,563 775,094,563 (a)
17,038,050 17,038,050
17,353,876 17,353,876
Total Sales to Ultimate Consumers 636,741,080 636 741,080
616,037,278 616,037,278 (b)
252 778,358 636 741 080 616 037,278
Sales for Resale - Account (447)
Total Sales of Electricity
(less) Provision for Rate Refunds - Account (449.
Total Revenues Net of Provisions for Refunds 252,778,358 636,741,080
535,245 535 245
681,519 681 519
29,072 161 28,523 564
616,037,278
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)
548,597 (c)
IFERC FORM NO.1 (ED. 12-S7) 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 03/20/2006 2005/Q4
FOOTNOTE DATA
Other Electric Revenues - Account (456)143,884 805 141,480,032 2,404,773 (d)
Total Operating Revenues $ 3,438,952,088 $ 2,819 961 440 $ 618,990,648
(a) The large industrial line on page 300 includes account 442.2 Industrial Sales of $724,822 698 and account 442.3 Irrigation Sales of $50 271,865.
(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.
540000 Office Rent
543000 Other RentlLeases
530190 Miscellaneous Contracts & Services
468,879
90,135
(10,417)
548,597
(d) The following schedule is a reconciliation between page 300 and 304 Other Electric Revenues. The items listed below do not have rate schedules.
Add
361000 Steam Sales
Less
385421 Interest Income - DSM CalT)'ing Charge
301938 Services Provided to Others - Revenue
038 811
462 799
171 240
2,404,772
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PaclfiCorp (1) An Original (Mo, Da, Yr)End of 2005/04
(2) Ei A Resubmission 03/20/2006
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 un billed revenue as of end of year for each applicable revenue account subheading.
Line NumDer ana title or Kate scneoUie Mvvn ::soia Kevenue Average, NumDer ~~n
T~s
r;::r ~~~~e
No.(a)(b)(c)of Cu(~\omers
(f)
1 Residential Sales
2 CA-PPL
3 06BLSKY01 R - BLUESKY ENERGY 316 455
4 06CHCKOOOR-CA RES CHECK M
5 06LNXO0109-REF/NREF ADV +195
6 06NETMT135 - CA RES NET 868 13,750 0885
7 060AL T015R-OUTD AR LGT SR 390 67,925 416 938 1742
8 06RESDOOOD-RES SRVC 290 214 887 199 25,683 300 0858
9 06RESDDC7 A-CA RES CLEAN A 111 0855
06RESDDLO6-CA LOW INCOME 53,264 601,926 745 11,225 0676
06RESDDM9M-MUL TI FAMILY 500 171 333 0803
06RESDDS8M-MULT FAM SBMET 379 105 285 933 0763
SMUD REVENUE IMPUTATIONS 236
06RESDOODN - CA RES SRVC -854 841 584 521 964 0856
UNBILLED REV - UNCOLLECT 000
UNBILLED REVENUE 337 000 0237
ID-UPL
07BLSKY01R-BLUESKY ENERGY 715 516
07LNXOO010-MNTHL Y 80%GUAR 029
07LNXOO035-ADV 80%MO GUAR 086
07LNXO0107-SUBDIV ADV+AIC 094
070ALCOO07-CUST OWN LIGHT 742 000 1584
070AL TO07R-SECURITY AR LG 830 944 2253
070ALT07AR-SECURITY AR LG 122 665 144 847 1940
070ALT07AR-SECURITY AR LG 217
07RESDOO01-RES SRVC 341 412 330,902 35,437 634 0801
07RESDOO01-RES SRVC 798,889
07RESDO036-RES SRVC-OPTIO 304,121 20,165 587 16,227 18,742 0663
07RESDO036-RES SRVC-OPTIO 079,251
BPA BALANCING ACCOUNT 631 300
UNBILLED REV - UNCOLLECT 000
UNBILLED REVENUE 529 581 000 0890
OR-PPL
01ACTSETUP-NEW SRVC SETUP
01CHCKOOOR-RES CHECK MTR
01COSTOOO4 - 01RESDOO04 191 646 162,188,958 0312
01 FXRENEWR - Fixed Renewable 50,341 658
01HABITO04 - 01RESDOO04 425 772 136 0304
01LNXO0102-LlNE EXT 80% G 000
01LNXO0105-CNTRCT $ MIN G
TOTAL Billed 49,504,09~807 927,440 056
Total Un billed Rev.(See Instr. 6)142 10E 034 000 084
TOTAL 49,646,20.819,961 440 056
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 2005/Q4
(2) 0 A Resubmission 03/20/2006
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 un billed revenue as of end of year for each applicable revenue account subheading.
I LIne Numcer ana Ime OT Kate scneaUie Mvvn ::;ola Kevenue Average. Numcer ~vvn oT ~ales ~folderNo.(a)(b)(c)of Cus~omers Per r~stomer
(f)
1 01LNXO0109-REF/NREF ADV +176
2 01NETMT135-NET METERING 79,518 172
3 01NETMT135-NET METERING 18,184
4 010AL T014R-OUTD AR LGT RE 591 392 679 209 119 1094
5 010ALT014R-OUTD AR LGT RE 29,589
6 010ALT015R-OUTDAR LGT RE 019 308 2548
7 01PTOUOO04 - 01RESDOO04 596 525,749 0692
8 01 RENEWO04 - 01 RESDOO04 104,208 117 542 0299
9 01RESDOO04-RES SRVC -61 237 139 829 451 275 887.5382
01RESDOO04-RES SRVC 661 934
01RESDO04T - RES Time Option 741 433 097
01 RESDO04T - RES Time Option 161 343
01 UPPLOOOR-BASE SCH FALL
01ZZMERGCR-MERGER CREDITS 166
BPA BALANCING ACCOUNT 979 149
OR ENRGY COST RECOV AMORT 540 527
SMUD REVENUE IMPUTATIONS 821 131
UNBILLED REV - UNCOLLECT -45,000
UNBILLED REVENUE 078 863 000 0918
UT-UPL
08ACTSETUP-NEW SRVC SETUP
08BLSKY01 R-BLUESKY ENERGY 151 234 13,714
08CFROOO01-MTH FACILITY S 409
08CHCKOOOR-UT RES CHECK M
08COOLKPRR - Utah Cool Keeper 614
08LNXOOO01-MTHL Y 80% GUAR 915
08LNXOOOO5-MTHL Y MIN GUAR 240
08LNXOO013-80% MNTHLY MIN 12,752
08LNXOO016 - 80% annual 591
08LNXO0101-AGR MTH+ADV+BT
31 08LNXO0107-SUBD ADV & AIC 376
32 08LNXO0108-ANN COST MTHL Y 230
33 08MHTPO025-MOBILE HOME &633 630,093 966,636 0593
34 08NETMT135 - Net Metering 102 464 286 0732
35 080AL TO07R-SECURITY AR LG 416 723 420 557 960 2118
36 08PTLDOOOR-POST TOP LIGHT 226 900 373 0748
37 08RESDOO01-RES SRVC 543,743 408 783,572 630,694 790 0737
38 08RESDOO02-RES SRVC-OPTIO 648 158 798 286 762 0964
39 08RESDOO03-LlFELINE PRGRM 140 716 209,676 19,139 352 0726
40 08RESD0150-RES ALL E NOT5
TOTAL Billed 49,504 094 807,927,440 056/
Total Unbilled Rev.(See Instr. 6)142,12,034 000 084/
TOTAL 49,646,20~819,961,440 056E
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This i!)ort Is:Date of Report Year/Period of Report
PaclfiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
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 un billed revenue as of end of year for each applicable revenue account subheading.
Line Numcer ana Ime or Kate SCnelJUle Mvvn ;:)011J "evenue Average Numcer ISwn or ;sales ~G~olderNo.(a)(b)(c)of Cu(~\omers Per r~stomer
(f)
1 08RFND1999-UTAH RATE RFND
2 08ZZMERGCR-MERGER CREDITS
3 SMUD REVENUE IMPUTATIONS 766,581
4 UNBILLED REV - UNCOLLECT 000
5 UNBILLED REVENUE 127 369,000 2234
6 WA- PPL
7 02BLSKY01R-BLUESKY ENERGY 15,353 345
8 02LNXO0109-REF/NREF ADV +160
9 020AL T013R-WA OUTD AR LGT 426 151 758 311 088 1064
020AL T013R-WA OUTD AR LGT 729
020ALT015R-WA OUTD AR LGT 219 000 1095
02RESDO016-WA RES SRVC 514,049 581 481 519 526 0625
02RESDO016-WA RES SRVC 033,709
02RESDO017-BILL ASSISTANC 40,333 526 902 326 340 0627
02RESDO017-BILL ASSISTANCE -453 757
02RESDO018-WA 3 PHASE RES 752 189 575 102 980 0689
02RESDO018-WA 3 PHASE RES 959
02RESD018X-WA 3 PHASE RES 714 387 500 0678
02RESD018X-WA 3 PHASE RES 036
02RFNDCENT - CENTRALIA RFND 168 117
02ZZMERGCR-MERGER CREDITS
BPA BALANCING ACCOUNT 885,490
UNBILLED REV - UNCOLLECT 17,000
UNBILLED REVENUE 746 200 000 0793
WY-PPL
05BLSKY01R-BLUESKY ENERGY 15,482 550
050AL T015R-OUTD AR LGT SR 203 143,953 245 966 1197
05RESDOO02-WY RES SRVC 712,205 354,314 381 341 0707
05RESDOO03-WY OPTIONAL RE 107,570 702 737 130 969 0623
05RESDO018-RES 3 PHASE SR 108 713 500 0714
05RESD0135 - Experimental Partial 2,468 800 0726
05RESD018X-RES 3 PHASE SR 969 000 0731
05RFNDCENT -CENTRALIA RFND
09BLSKY01 R-BLUESKY ENERGY
09LNXO0108-ANN COST MTHLY 336
36 09RESD0201-RES SRVC 195 13,751 471 0705
SMUD REVENUE IMPUTATIONS 601
38 09NETMT135 - WY RES NET 729 000 0729
39 UNBILLED REV - UNCOLLECT 000
UNBILLED REVENUE 636 299,000 0645
TOTAL Billed 504 094 807 927 440 0561
Total Un billed Rev.(See Instr. 6)142 034,000 0841
TOTAL 49,646 20.:819 961 440 056e
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 2005/Q4
(2) Fi A Resubmission 03/20/2006
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.
Numoer ana I !tie or Kate scneoule Mvvn ;:,010 ~evenue 1\verage NumDer ~vvn- or ,?ales ~BfolderNo.(a)(b)(c)of cu(~)omers Per 9~stomer
(f)
1 WY - UPL
2 05BLSKY01R-BLUESKY ENERGY 537 188
3 05RESDOO02-WY RES SRVC 493 34,501 804 0700
4 05RESDOO03-WY OPTIONAL RE 102 337 20,400 0621
5 05RESDO018-RES 3 PHASE SR 304 000 1013
6 05UPPLOOOR-BASE SCH FALL
7 09BLSKY01 R-BLUESKY ENERGY
8 09INVCHGOR-INVEST MNT CHG
9 090AL T207R-SECURITY AR LG 29,548 105 867 3247
09RESD0201-RES SRVC 71,743 357 646 207 792 0747
09RESD0205-RES SRVC ALL E 40,016 649 956 242 17,848 0662
09NETMT135 - WY RES NET 298 000 0634
SMUD REVENUE IMPUTATIONS 535
UNBILLED REVENUE 280 000 0036
Less Multiple Billings 861
Total Residential Sales 650,121 968 845 322 379,654 10,619 0661
Commercial Sales
CA - PPL
06BLSKY01 N - BLUESKY ENERGY
06CHCKOOON-CA NRES CHECK
06GNSVO025-CA GEN SRVC 62,734 821 317 680 391 1087
06GNSV025F-GEN SRVC-c:: 20 898 112,258 761 1250
06GNSVOA32-GEN SRVC-20 KW 73,359 533,687 862 103 0891
06GNSVA32M-GEN SRVC-20 KW
06LGSV048T-LRG GEN SERV 68,619 769,925 238,091 0549
06LGSVOA36-LRG GEN SRVC-83,381 197 005 201 414 831 0743
06LNXO0102-LlNE EXT 80% G 298
06LNXO0105-CNTRCT $ MIN G 611
06LNXO0109-REF/NREF ADV +255
060AL T015N-OUTD AR LGT SR 770 135,634 563 368 1761
06RCFLO042-AIRWAY & ATHLE 204 26,846 231 1316
06WHSVO031-COMM WTR HEATI 270 23,851 182 0883
SMUD REVENUE IMPUTATIONS 221
06LNXO0103-LlNE EXT 80% G 239
06LNXO0110-REF/NREF ADV +815
UNBILLED REVENUE 19,000 2375
ID - UPL
07BLSKY01 N-BLUESKY ENERGY 263
TOTAL Billed 49,504,094 807 927 440 0561
Total Un billed Rev.(See Instr. 6)142 10a 034 000 0847
TOTAL 646,20:./819 961,440 056
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 2005/Q4
(2) Fi A Resubmission 03/20/2006
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.
....lOe Number and Title OJ t(ate scneoUie Mvvn ~OIO t(evenue Average, Numcer ~:n
r~s a::r ~W~olderNo.(a)(b)(c)of Cu(~)omers
(f)
1 07CISHO019-COMM & IND SPA 293 685 374 307 33,528 0666
2 07GNSVOOO6-GEN SRVC-LRG P 203 344 713,213 893 227 709 0576
3 07GNSVOOO9-GEN SRVC-HI VO 30,240 289,050 30,240,000 0426
4 07GNSVO023-GEN SRVC-SML P 98,716 426,052 195 19,002 0752
5 07GNSVO035-GEN SRVCOPTION 965 112 456 982 500 0572
6 07GNSVO06A-GEN SRVC-LRG P 23,813 599,240 197 120,878 0672
7 07GNSVO06A-GEN SRVC-LRG P -475,107
8 07GNSV023A-GEN SRVC-SML P 383 157,535 074 392 0805
9 07GNSV023A-GEN SRVC-SML P 287 115
07GNSV023F-GEN SRVC SML P 538 857 1269
07LNXOO010-MNTHL Y 80%GUAR 134
07LNXOO035-ADV 80%MO GUAR 173,186
07 LNXOO040-ADV +R E F C H G +80%36,449
070ALTO07N-SECURITY AR LG 281 48,121 201 398 1712
070AL T07 AN-SECURITY AR LG 146 786 1951
070AL T07 AN-SECURITY AR LG 192
07ZZMERGCR-MERGER CREDITS
07LNXO0312 - ID LINE EXT 754
07LNXOO015-ANNUAL 80%GUAR 145
07LNXO0311 - LINE EXT 80%013
07BLSKY01N -ID BLUESKY
07LNXOO020 - ID MONTHLY 483
07LNXO0300 - 80% MONTHLY MIN 704
BPA BALANCING ACCOUNT 570,099
UNBILLED REVENUE 651 35,000 0538
OR - PPL
01 BLSKY01 N-BLUESKY ENERGY 444
01 BULKBSKY - BULK BLUESKY 23,195
01COSTO023, OR GEN SRV, COST 941 301 290,400 0375
01 COSTO048 - 01 LGSVO048 737,013 22,628,151 0307
01COST023F - OR GEN SRV -273 131 388 0401
01COSTB023 - OR GEN SRV 93,161 632,896 0390
01 COSTB028, OR GEN SRV, COST 725 735,631 0336
01COSTL028, OR LRG SRV, COST 618 096 770,608 0336
01COSTL030 - OR LRG GEN SRV 759,423 25,469,160 0335
01COSTS028, OR GEN SERV 200 202 938 544 0341
01COSTS030 - OR GEN SRV CBS;;.109,876 670 479 0334
01 FXRENEWN - Fixed Renewable 821 133
01GNSBO023 - BPA DISC, 0:: 30 kW 962,036
01GNSBO023, OR GEN SRV, BPA 237,925 797 92.1288
TOTAL Billed 504,09;:807 927 440 056
Total Unbilled Rev.(See Instr. 6)142,1OE 12,034,000 0847
TOTAL 49,646 20.819 961,440 056f
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 2005/Q4(2) 0 A Resubmission 03/20/2006
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 or Kate scneaUie Mvvn ~ola Kevenue Average, NumDer ~vvn or?ales 'i~Rfo lderNo.(a)(b)(c)of Cus~omers Per ?~stomer
(f)
1 01 GNSBO028 - OR GEN SRVC 921 834
2 01GNSBO028, OR GEN SRV, BPA 308,802 513
3 01GNSBO030 - OR GEN SRV, :. 200 39,371
4 01GNSBO030 - OR GEN SRV 496
5 01GNSB023T - OR GEN SRV - TOU 948 109
6 01GNSB023T - OR GEN SRVC,15,711
7 01GNSVO023, OR GEN SRV, c: 30 30,093,380 51,402 510.0573
8 01GNSVO028, OR GEN SRV:. 30 31,284,921 128
9 01GNSVO030 - OR GEN SRV, :. 200 182 617 113
01GNSV023F - OR GEN SRV -175 012 550 960 724 0769
01GNSV023M - OR GEN SRV 649 000 0509
01GNSV023T, OR GEN SRV, TOU 136,224 238
01HABTO023, OR HABITAT 520 036 0382
01HABTB023 - OR HABITAT 110 4,420 0402
01 LGSBO028 - OR LRG GEN SRVC,-478,923
01LGSBO028, OR LRG GEN SRV 965 258 125
01LGSBO030, GEN DEL SRV, ~ 200 -415 244
01LGSBO030, GEN DEL SRV :' 200 676,129
01LGSVO028, OR LRG GEN SRV c:832 737 586
01LGSVO030 - OR LRG GEN SRV,887,402 468
01LGSVO048-1000KW AND OVR 556,996
01LGSV048M-LRG GEN SRVC 1 740 943,003 740 000 0376
01LNXO0100-LlNE EXT 60% G 13,602
01LNXO0102-LlNE EXT 80% G 305 499
01LNXO0103-LlNE EXT 80% G 037
01LNXO0105-CNTRCT $ MIN G 13,840
01LNXO0109-REF/NREF ADV +285 459
01LNXO0110-REF/NREF ADV +597
01LNXO0120 - Line Extension 60% G 912
01 LNXO0300 - LINE EXT 80%413
01LNXO0311 - LINE EXT 80% G 861
01 LPRS047M-PART REQ SRVC 962 747 639 320 667 1074
01NMT23135 - OR NET MTR, GEN,780
010ALT014N-OUTD AR LGT NR 213 248,982 280 729 1125
010ALT014N-OUTD AR LGT NR 18,156
010ALT015N-OUTD AR LGT NR 443 796,465 291 565 0943
01 PRSVL36M, OR PRT REQ SRV
, ~
037 81,265 518,500 0268
01PRSVM36M - OR PRT SRV, 31 -449 662 224 500 0727
01PTOUO023, OR GEN SRV, TOU 574 144,834 0920
01PTOUB023, OR GEN SRV, TOU 624 55,561 0890
TOTAL Billed 49,504,09~807 927,440 056
Total Un billed Rev.(See Instr. 6)142,10e 12,034 000 084/
TOTAL 646,20~819 961 440 0568
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 2005/Q4(2) 0 A Resubmission 03/20/2006
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 Numcer ana !ltIe or Kate scneaUie Mwn ::soia Kevenue Average Numcer I5:wn or :;sales ~~olderNo.(a)(b)(c)of Cus~omers Per r~stomer
(f)
1 01RCFLOO54-REC FIELD LGT 786 68,395 939 0870
2 01 RENWO023, OR RENW USAGE 523 135 355 0384
3 01 RENWB023 - OR RENEWABLE 366 601 0399
4 01STDAY023 - OR DAY STD OFR,084 859 0663
5 01STDAY028 - OR DAY STD OFF 323 154,891 0667
6 01STDAY030 - OR STD DAY OFF 039 260,542 0645
7 01XTRNBSKY - Blue Sky 893
8 01ZZMERGCR-MERGER CREDITS 697
9 BPA BALANCING ACCOUNT 154,128
OR ENRGY COST RECOV AMORT 842 437
01LGSBO048 - LG GEN SVC;:.124,899
01LGSBO048 - LG GEN SVC;:.210 731
01NMT28135 - OR NET MTR, GEN 546
01LGSV028M - OR LGSV, 0::1000 864 000 0637
01GNSV030M - OR GEN SRV, 200 150 125 150,000 0475
01GNSV0728 - OR GEN SVC DIR 179
01GNSV0730 -OR GEN SVC DIR 528,301
01GNSV0748 LG GEN SVC DIR 41,732
SMUD REVENUE IMPUTATIONS 743,152
UNBILLED REVENUE 2,401 224,000 0933
UT - UPL
08BLSKY01M - BLUE SKY
08BLSKY01N-BLUESKY ENERGY 951 327
08BULKBSKY - BULK BLUESKY 30,689
08CFROO051-MTH FAC SRVCHG 645
08CFROO052-ANN FAC SVCCHG
08CHCKOOON-UT NRES CHECK
08COOLKPRN - AIC DIRECT LOAD 877
08GNSVOOO6-GEN SRVC-DISTR 4,451,400 255,479,003 10,294 432,427 0574
08GNSVOO09-GEN SRVC-HI VO 189,326 371,334 518 111 0389
08GNSVO023-GEN SRVC-DISTR 068 097 932 468 064 395 0692
08GNSVO06A-GEN SRVC-ENERG 154 890 799 041 1,466 105 655 0762
08GNSVO06B-GEN SRVC-DEM&809 386,770 400,529 0568
08GNSVO06M-MNL DIST VOL TG 936 819,245 117 000 0484
08GNSVO09A-GEN SRVC HI VO 278 595 705 14,278,000 0417
08GNSVO09M-MANL HIGH VOLT 966 637 002 21,983 000 0372
08GNSV023F-GEN SRVC FIXED 773 132,703 117 154 0748
08GNSV023M-GNSV DIST VOLT 207 13,945 29,571 0674
08GNSV06AM-MNL ENERGY TOD 365 903 365,000 0622
08GNSV06BM-MNL DEMAND TOD 115 602 500 0139
TOTAL Billed 49,504,09~807,927,440 0561
Total Un billed Rev.(See Instr. 6)142 10f 12,034,000 084/
TOTAL 646,20..819,961,440 056f
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This 'mort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
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.
NumDer ano ,me or t'(ate scneoUie Mwn ;::,010 t'(evenue 1\verage NumDer ~vvn or ?ales ~GfoNo.of Cus~omers Per cr~stomer(a)(b)(c)(f)
1 08GNSV06MN-GNSV DIST VOLT 475 107 561 330 076 0516
2 08GNSV09AM-MAN TOD HIVOL T 395 18,562 395 000 0470
3 08GNSV09LM-GEN TOD LAGOON 737 338,461 737 000 0437
4 08LNXOOO02-MTHL Y 80% GUAR 373 433
5 OBLNXOOOQ4-ANNUAL 80%GUAR 68,206
6 08LNXOOO06-FIXD MTHL Y MIN 179
7 08LNXOO014-80% MIN MNTHL Y 151 742
8 OBLNXOO017 -ADV/REF&80%ANN 509
9 08LNXO0150-AGR MTH GUAR M 35,024
08LNXO0151-AGR MTH+ADV+BT 643
08LNXO0153-AGR ANN+ADV+BT 320
08LNXO0158-ANNUALCOST MTH 32,978
08LNXO0300 - LINE EXT 80% PLUS 182,926
08NMT23135 - UT NET MTR, GEN,673 000 0841
080AL TO07N-SECURITY AR LG 10,303 768,151 968 074 1716
08POLEO075-POLES W/LiGHT 021
08PRSV031M-BKUP MNT&SUPPL 781 688 610 260 333 0539
08PTLDOOON-POST TOP LIGHT 867 125 0749
08SLC1202F-TRAFFIC giG NM 254 546 938 0612
08SLCU1202-TRAF & OTHER S 254 523 350 583 0682
08SLCU1203-MTR OUTDONIGHT 782 621,704 253 711 0708
08XTRNBLUE. BLUESKY ANN 979
08ZZMERGCR-MERGER CREDITS 319
SMUD REVENUE IMPUTATIONS 914 371
OBGNSVO06T - UT GEN SVC TOU 491 110 670 0444
08LNXO0311 - LINE EXT 80%195
08GNSVOO08 - UT GEN SVC TOU ;:.667 760 859,963 113 909 381 0507
08GNSVO08M - UT GEN SVC TOU 752 564 486 550,400 0537
UNBILLED REVENUE 45,496 951 000 0649
WA - PPL
02BLSKY01 N-BLUESKY ENERGY 287
02GNSVO024-WA GEN SRVC 449 355 28,471,809 987 34,600 0634
02GNSVO025-WA GEN SRVC DO 003 235,633 301 542 0674
02GNSVO025-WA GEN SRVC DO 539,999
35 02GNSV024F-WA GEN SRVC-210 112 573 123 837 0930
02GNSV025F-GEN SRVC DOM/F 318 22,922 909 0721
37 02GNSV025F-GEN SRVC DOM/F -443
38 02GNSV24FP-GNSV SEASONAL 364 92,486 118 085 2541
39 02GNSV24FP-GNSV Seasonal 110
02LGSVO035-WA LRG GEN SRV 725 4,426,579 100 867 250 0510
TOTAL Billed 504,09~807 927,440 056
Total Un billed Rev.(See Instr. 6)142 10f 12,034 000 084/
TOTAL 49,646 819,961,440 056
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 2005/04(2) nA Resubmission 03/20/2006
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 Numcer ana ,me or Kate scneaule Mvvn ~ola Kevenue Average Numcer ~vvn or ~ales ~~~foNo.(a)(b)(c)of cu(~\omers Per ?~stomer
(f)
1 02LGSVO035-WA LRG GEN SRV 974,886
2 02LGSVO036-WA LRG GEN SRV 661 739 388 697 766 863 889 0520
3 02LGSV048T -LRG GEN SRVC 1 155,740 369,618 370,345 0473
4 02LNXO0102-LlNE EXT 80% G 38,427
5 02LNXO0103-LlNE EXT 80% G
6 02LNXO0105-CNTRCT $ MIN G 932
7 02LNXO0109-REF/NREF ADV +67,160
8 02LNXO0110-REF/NREF ADV +236
9 02LNXO0112-YR INCURRED CH 669
02LNXO0300-LlNE EXT 80% G 23,150
020ALT013N-WA OUTD AR LGT 820 86,786 616 331 1058
020AL T013N-WA OUTD AR LGT 913
020AL T015N-WA OUTD AR LGT 060 201 911 891 312 0980
02RCFLOO54-WA REC FIELD L 282 21,532 9,400 0764
02RFNDCENT - CENTRALIA RFND 862,859
02ZZMERGCR-MERGER CREDITS 567
02NMT24135, Net metering, WA 287 000 0718
BPA BALANCING ACCOUNT 26,476
UNBILLED REVENUE 10,100 681 000 0674
WY - PPL
05BLSKY01 N-BLUESKY ENERGY 908
05GNSVO025-WY GEN SRVC 816,017 53,000,990 19,576 685 0650
05GNSV025F-GEN SRVC-FL RA 054 121 035 196 378 1148
05LGS45025-LRG GEN SRVC 142,948 022,629 158 904 734 0561
05LGSV046T-LRG GEN SERV 209,603 344,062 10,480,150 0446
05LNXO0100-LlNE EXT 60% G 116
05LNXO0102-LlNE EXT 80% G 140,705
05LNXO0105-CNTRCT $ MIN G 343
05LNXO0109-REF/NREF ADV +298,502
05LNXO0110-REF/NREF ADV +399
05LNXO0114- TEMP SVC 12MO;:'011
05NMT25135 - WY NET MTR, GEN 247 18,903 123 500 0765
050AL T015N-OUTD AR LGT SR 673 428 755 886 948 1167
05RCFLOO54-WY REC FIELD L 793 54,553 13,912 0688
05RFNDCENT -CENTRALIA RFND
09GNSV0206-GEN SRVC-SINGL 243 000 2430
05LNXO0300 - LINE EXT 80%540
05LNXO0311 - LINE EXT 80%843
SMUD REVENUE IMPUTATIONS 24,002
UNBILLED REVENUE 707 370,000 0648
TOTAL Billed 504 0941 807 927,440 0567
Total Un billed Rev.(See Instr. 6)142,034 000 0847
TOTAL 49,646 20~819,961 440 056S
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 2005/Q4
(2) 0 A Resubmission 03/20/2006
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 un billed revenue as of end of year for each applicable revenue account subheading.
Line NumDer ana I IDe OT Kate scneaule Mvvn ~ola Kevenue Average NumDer ~vvn oT ~ales ~~~e lderNo.(c)of Cus~omers Per C(~stomer(a)(b)(f)
1 05BLSKY01N-BLUESKY ENERGY
2 05GNSVO025-WY GEN SRVC 103 980 10,300 0775
3 05LNXO0102-LlNE EXT 80% G 306
4 05LNXO0103-LlNE EXT 80% G 619
5 05LNXO0109-REF/NREF ADV +42,944
6 05LNXO0110-REF/NREF ADV +754
7 09GNSV0206-GEN SRVC-SINGL 110,814 008,149 236 49,559 0632
8 09GNSV206F-GEN SRVC-FIXED 259 24,403 641 0942
9 09GNSV206M-GENSERV MANUAL 330 141 122 776 667 0606
09INVCHGON-INVEST MNT CHG
090AL T207N-SECURITY AR LG 299 906 147 034 3107
09SLCU2123-MTR OUTDONIGHT 091 667 0813
09RFNDCENT -CENTRALIA RFND
05LNXO0300 - LINE EXT 80%800
05LNXO0311 - LINE EXT 80%267
SMUD REVENUE IMPUTATIONS 055
UNBILLED REVENUE 372 261 000 0597
Less Multiple Billings 672
Total Commercial Sales - 442.768 597 858,409 269 194 933 762 0581
Industrial Sales
CA - PPL
06GNSVO025-CA GEN SRVC 929 102 997 105 848 1109
06GNSVOA32-GEN SRVC-20 KW 565 157 798 71,136 1008
06GNSVA32M-GEN SRVC-20 KW
06LGSV048M - LG GEN SRV TOU 140 417 167 140,000 0512
06LGSV048T -LRG GEN SERV 796 328,177 699 000 0544
06LGSVOA36-LRG GEN SRVC-703 782 884 570,765 0807
06LNXO0109-REF/NREF ADV +087
SMUD REVENUE IMPUTATIONS 729
UNBILLED REVENUE 707 000 0495
ID - UPL
07CFROOO01-MTH FACILITY S 217
07CISHO019-COMM & IND SPA 169 118 143 0717
07GNSVOOO6-GEN SRVC-LRG P 85,876 412 692 112 766,750 0514
07GNSVOOO8-GEN SRVC-MEDIU 350 127 253 175,000 0542
38 07GNSVOO09-GEN SRVC-HI VO 82,329 500 868 7,484,455 0425
39 07GNSVO023-GEN SRVC-SML P 10,578 762 864 364 29,060 0721
07GNSVO06A-GEN SRVC-LRG P 489 403 728 170 763 0622
TOTAL Billed 49,504 09~807,927 440 056
Total Unbilled Rev.(See Instr. 6)142 034,000 084
TOTAL 49,646,202 819,961 440 056
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 2005/Q4(2) 0 A Resubmission 03/20/2006
SALES OF ELECTRICITY BY RATE St 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 I)ue oJ l'(aIe scneauae IVlvvn o::.Ola I'(evenue Average NumDer ~wn oT ~ales ~~'$e lderNo.(a)(b)(c)of Cu(~\omers Per y~stomer
(f)
1 07GNSVO06A-GEN SRVC-LRG P 128 810
2 07GNSV023A-GEN SRVC-SML P 341 205,792 273 575 0879
3 07GNSV023A-GEN SRVC-SML P -46 445
4 07LNXOO035-ADV 80%MO GUAR 837
5 07LNXO0108-ANN COST MTHL Y 996
6 070ALTO07N-SECURITY AR LG 365 947 1869
7 070AL T07 AN-SECURITY AR LG 314 500 3140
8 070ALT07AN-SECURITY AR LG
9 07SLCU1201-TRAF SIGNAL SY 070 333 1070
07SPCLOO01 342 900 792 866 342 900 000 0304
07SPCLOO02 112 900 904,013 112,900,000 0346
BPA BALANCING ACCOUNT 110 052
UNBILLED REVENUE 167 280 000 0672
OR - PPL
01 BLSKY01 N-BLUESKY ENERGY
01COSTO023, OR GEN SRV, COST 23,439 880 100 0375
01COSTO048 - 01LGSVO048 654 814 49,616 110 0300
01COST023F - OR GEN SRV -140 0467
01 COSTB023 - OR GEN SRV 357 14,097 0395
01COSTB028, OR GEN SRV, COST 014 .0338
01COSTL028, OR LRG SRV, COST 54,458 831,303 0336
01COSTL030 - OR LRG GEN SRV,277,604 325,374 0336
01COSTS028, OR GEN SERV 63,618 171,153 0341
01COSTS030 - OR GEN SRV CBS:;.36,248 1 ,206,797 0333
01GNSBO023 - BPA DISC, c:. 30 kW 727
01GNSBO023, OR GEN SRV, BPA 338
01GNSBO028 - OR GEN SRVC,512
01GNSBO028, OR GEN SRV, BPA,18,783
01GNSVO023, OR GEN SRV, c:. 30 790,532 219
01GNSVO028, OR GEN SRV:;. 30 300 387 431
01GNSVO030 - OR GEN SRV,:;' 200 814 552
01GNSV023F - OR GEN SRV -484
01GNSV023M - OR GEN SRV
01GNSV023T, OR GEN SRV, TOU 330
01HABTO023, OR HABITAT 820 0371
01 LGSBO028 - OR LRG GEN SRVC,332
01LGSBO028, OR LRG GEN SRV 522
01 LGSBO030, GEN DEL SRV, :;. 200 922
01LGSBO030, GEN DEL SRV, :;. 200 51,467
01LGSVO028, OR LRG GEN SRV c::217 615 163
TOTAL Billed 49,504 09~807 927,440 0567
Total Un billed Rev.(See Instr. 6)142,10E 12,034 000 0841
TOTAL 49,646,20.819,961 440 056E
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 2005/a4(2) nA Resubmission 03/20/2006
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 un billed revenue as of end of year for each applicable revenue account subheading.
LIne NumDer ana Ime or Kate scneaUie IVlvvn ~Ola ~evenue I'\verage NumDer '1vvn or ~ales "Rww~e lderNo.(a)(b)(c)of Cus~omers Per C(~stomer
(f)
1 01LGSVO030 - OR LRG GEN SRV 787 194 175
2 01LGSVO048-1000KW AND OVR 17,747 960 120
3 01LGSV048M-LRG GEN SRVC 1 601 503 087 279 120,300,600 0351
4 01LNXO0102-LINE EXT 80% G 252
5 01LNXO0105-CNTRCT $ MIN G 515
601LNXO0109-REF/NREF ADV +352
7 01 LNXO0300 - LINE EXT 80%988
8 01 LPRS047M-PART REQ SRVC 225,998 982 291 56,499,500 0442
9 01 OAL T014N-OUTD AR LGT NR 220 111 1220
010ALT014N-OUTD AR LGT NR
010ALT015N-OUTD AR LGT NR 544 378 170 200 0889
01PRSVL36M, OR PRT REa SRV
, ~
913 000 6319
01PRSVS36M - OR PRT REa SRV 700 000 1400
01PTOUO023, OR GEN SRV, TOU 3,400 0680
01 RENWO023, OR RENW USAGE 119 528 0381
01 RENWB023 - OR RENEWABLE 159 0398
01ZZMERGCR-MERGER CREDITS 191
BPA BALANCING ACCOUNT 832
OR ENRGY COST RECOV AMORT 097 623
01 BULKBSKY - BULK BLUESKY 540
01STDAY023 - OR DAY STD OFR,771 0656
01LGSV028M - OR LGSV, c::1000 069 42,000 0969
SMUD REVENUE IMPUTATIONS 461 569
UNBILLED REVENUE 098 716,000 0396
UT - UPL
08BLSKY01 N-BLUESKY ENERGY
08CFROO051-MTH FAC SRVCHG 009
08EFOPO021-ELEC FURNACE 0 292 156,533 764 000 0683
08EFOP021 M-ELEC FURNACE 0 1,483 129,589 741,500 0874
08GNSVOO06-GEN SRVC-DISTR 917 667 53,889,201 375 667,394 0587
08GNSVOOO9-GEN SRVG-HI VO 175,581 78,270,471 106 20,524 349 0360
08GNSVO023-GEN SRVG-DISTR 210 268,506 974 15,151 0709
08GNSVO06A-GEN SRVC-ENERG 49,982 236 030 202 247 436 0848
08GNSVO06B-GEN SRVG-DEM&703 185,060 386,143 0685
08GNSVO06M-MNL DIST VOL TG 085 994,970 271 250 0472
08GNSVO09A-GEN SRVC HI VO 206 853,980 701 000 0527
08GNSVO09M-MANL HIGH VOLT 650 912 877 236 59,173 818 0351
08GNSV023F-GEN SRVC FIXED 308 500 2616
08GNSV06MN-GNSV DIST VOLT 965 53,280 53,611 0552
08GNSV09AM-MAN TOD HIVOL T 180 882 180 000 0702
TOTAL Billed 49,504 094 807 927 440 0561
Total Unbilled Rev.(See Instr. 6)142 034 000 0847
TOTAL 646,20~819,961 440 056E
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This j!prt Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/04(2) n A Resubmission 03/20/2006
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 Number ana Ime or N.ate scneaule Mvvn ~ola N.evenue Average. Numcer ~~ny~s a::r v ~~olderNo.(a)(b)of Cus~omers(c)(f)
1 08LNXOOO02-MTHL Y 80% GUAR 824
2 08LNXOOOO4-ANNUAL 80%GUAR 569
3 08LNXOO014-80% MIN MNTHL Y 596
4 08LNXOO017-ADVIREF&80%ANN 524
5 08LNXO0150-AGR MTH GUAR M 728
6 08LNXO0151-AGR MTH+ADV+BT 297
7 08LNXO0158-ANNUALCOST MTH 179
8 08LNXO0300 - LINE EXT 80% PLUS 623
9 080ALTO07N-SECURITY AR LG 771 278,956 566 129 1575
08PRSV031 M-BKUP MNT&SUPPL 138 404 971 138,000 3559
08SLCU1202-TRAF & OTHER S 151 250 0630
08SLCU1203-MTR OUTDONIGHT 598 667 2598
08SPCLOO01 583,725 436,934 583,725,000 0299
08SPCLOO02 720 059 377 272 720,059 000 0269
08SPCLOO03 730,664 24,501 595 730 664,000 0335
08SPCLOO05 232 170 652 054 232,170 000 0330
08ZZMERGCR-MERGER CREDITS
SMUD REVENUE IMPUTATIONS 753,224
08GNSV06AM-MNL ENERGY TOD 367 000 0918
08GNSVO06T - UT GEN SVC TOU 674 30,352 0450
08GNSVOO08 - UT GEN SVC TOU ;.736,800 868,900 518 367 0514
08GNSVO08M - UT GEN SVC TOU 59,638 076,094 7,454 750 0516
UNBILLED REVENUE 23,389 751 000 0321
WA - PPL
02GNSVO024-WA GEN SRVC 244 222 349 386 49,855 0635
02GNSVO025-WA GEN SRVC DO 665 183,349 115 23,174 0688
02GNSVO025-WA GEN SRVC DO 29,979
02GNSV024F-WA GEN SRVC-FL 438 250 1648
02GNSV24FP-GNSV SEASONAL 998 000 4990
02GNSV24FP-GNSV Seasonal
02LGSVO035-WA LRG GEN SRV 786 381 261 159 533 0797
02LGSVO035-WA LRG GEN SRV 53,845
33 02LGSVO036-WA LRG GEN SRV 164 165 695 247 142 156,092 0530
34 02LGSV048M-WA LRG GEN SRV 994 978 019 93,994 000 0423
35 02LGSV048T-LRG GEN SRVC 1 744 533 211 831 272 371 0419
36 02LNXO0102-LlNE EXT 80% G 208
37 02LNXO0109-REF/NREF ADV +340
38 020AL T013N-WA OUTD AR LGT 783 667 1081
39 020AL T013N-WA OUTD AR LGT 334
020AL T015N-WA OUTD AR LGT 177 16,467 688 0930
TOTAL Billed 49,504 094 807,927,440 056
Total Unbilled Rev.(See Instr. 6)142,034 000 084
TOTAL 646,20~819,961 440 056E
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 2005/04
(2) Fi A Resubmission 03/20/2006
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.
...lOe Number and Ime OT N:ate scneaule Mvvn ;)Ola N:evenue f\verage. Numcer ~~~n
cr~s
a::r ~~~e lderNo.(a)(b)(c)of Cu(~)omers
(1)
1 02PRSV47TM-LRG PART REQMT 22,019 2,408,717 . 2 009,500 1094
2 02RFNDCENT - CENTRALIA RFND 547 566
3 02ZZMERGCR-MERGER CREDITS 085
4 02LNXO0300-LlNE EXT 80% G 631
5 02LGSB048T - WA GEN SRVC,547
6 02LGSB048T - WA GEN SRVC, NO 189
7 BPA BALANCING ACCOUNT 251
8 UNBILLED REVENUE 776 297 000 1070
9 WY - PPL
05GNSVO025-WY GEN SRVC 175,462 10,226,174 642 106 859 0583
05GNSV025F-GEN SRVC-FL RA 289 188 0999
05GNSV025M - General Service 660 499,671 276 667 0639
05LGS45025-LRG GEN SRVC 89,506 582,686 657 519 0512
05LGSV046M-WY LRG GEN SRV 672,443 042,432 96,063,286 0432
05LGSVO46T-LRG GEN SERV 479 940 59,870 749 665,667 0405
05LGSV048M- TOU~1 OOOKW MAN 909,462 28,866 817 454,731 000 0317
05LGSV048T-LRG GENSRV TIM 555,666 18,581,805 92,611 000 0334
05LNXO0100-LlNE EXT 60% G 12,369
05LNXO0102-LlNE EXT 80% G 221 069
05LNXO0105-CNTRCT $ MIN G 48,074
05LNXO0109-REF/NREF ADV +294 741
050ALT015N-OUTD AR LGT SR 10,388 885 1060
05PRSV033M-PART SERV REO 024,727 762 008 204 945,400 0378
SMUD REVENUE IMPUTATIONS 639,847
05LNXO0300 - LINE EXT 80%804
UNBILLED REVENUE 667 572 000 0324
WY - UPL
05LNXO0109-REF/NREF ADV +647
09GNSV0206-GEN SRVC-SINGL 213 748,898 395 119,527 0582
30 09GNSV0217-LRG POWER SRVC 359,300 12,370,922 51,328,571 0344
31 09GNSV206M-GENSERV MANUAL 757 181 802 939,250 0484
32 09GNSV217M-LRG POWER SRVC 304 425 10,402 393 60,885 000 0342
33 090AL T207N-SECURITY AR LG 822 750 2603
34 09PRSV218M-BKUP MNT SUPPL 117 165 657 882 055 000 0398
35 SMUD REVENUE IMPUTATIONS 894
36 UNBILLED REVENUE 537 314 000 0368
37 Less Multiple Billings 208
39 Total Industrial Sales - 442.18,425,046 724 822,698 649 581 685 0393
TOTAL Billed 49,504 094 807,927,440 0567
Total Un billed Rev.(See Instr. 6)142 12,034 000 084/
TOTAL 49,646,20.819,961 440 056
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 2005/Q4(2) DA Resubmission 03/20/2006
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 Numcer ana Ime OT Kate scneaule Mwn ~ola Kevenue Average. Numcer ~~n
9~sr;::r ~W~foNo.(a)(b)(c)of Cus~omers
(f)
1 lITigation Sales
2 CA- PPL
3 06APSVO020-AG PMP SRVC 52,672 298 712 299 40,548 0816
4 06LNXO0103-LINE EXT 80% G
5 06LNXO0110-REF/NREF ADV +864
6 06SLXOOO01-KLAM FALLS MIN 35,908
7 06SLXOOO02-KLAM FALLS IRG 832
8 06UKRBO035-KLAM OFF PROJ
, "
000 0075
9 06USBRO040-KLAM IRG ONPRJ 918 143 507 610 210 0060
06USBR033T USBR 240 44,426 284,651 0036
06LNXO0109-REF/NREF ADV +920
IRRIGATION UNBILLED 256 000 0078
ID - UPL
07APSA010L - IRG & Pump BPA 14,655,791
07APSA010L -IRG & Pump Large 463,596 28,634 199 344 197 780 0618
07APSA010S -IRG & Pump BPA 126 674
07APSA010S -IRG & Pump Small 998 313,713 277 14,433 0785
07 APSAL 1 OX - IRG & PUMP - Large 548 636 812 356 116,708 0635
07APSAS10X -IRG & PUMP - Small 367 127 426 157 707 0932
07APSB010L -IRG & Pump BPA
07APSB010L -IRG & Pump Large 130
07APSB010S -IRG & Pump BPA
07APSB010S -IRG & Pump Large
07APSBL10X -IRG & PUMP - Large
07APSBS10X -IRG & PUMP - Sm
07APSC010L -IRG PUMP Srv BPA 37,919
07APSC010L -IRG PUMP Srv Large 341 37,937 738 490 0283
07APSC010S -IRG PUMP Srv BPA 119
07APSC010S -IRG PUMP SRV 549 318 5490
07APSCL 10X - was 07APSC10LX 936 56,859 213 -4,394 0607
07APSCS10X - was 07APSC10SX 0140
07APSVCNLL-LRG LOAD CANAL 566 103,110 342,767 0536
07 APSVCNLL-LRG LOAD CANAL -628 573
07 APSVCNLS-SML LOAD CANAL 055 600 0882
07 APSVCNLS-SML LOAD CANAL 252
07BPADEBIT-BPA ADJUST FEE 536,269
07)..NXOO015-ANNUAL 80%GUAR 192
07LNXOO035-ADV 80%MO GUAR 289
07 LNX 00040-ADV + RE F CH G+80%140,018
07LNXO0107-SUBD ADV & AIC 097
TOTAL Billed 49,504,09~807,927,440 056
Total Unbilled Rev.(See Instr. 6)142,034,000 084/
TOTAL 646,20.819 961 440 056€
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 2005/04(2) n A Resubmisslon 03/20/2006
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 un billed revenue as of end of year for each applicable revenue account subheading.
I,-me Numoer ana ,me or Kate scneaule Mvvn ;sold "Revenue '1\verage Nurnoer ~vvn oT ~ales ~R~e lderNo.(a)(b)(c)of C~~\omers Per '(~stomer
(f)
1 07ZZMERGCR-MERGER CREDITS
2 07APSN010L -ID LG IRR & PUMP 387 685 96,750 0638
3 07APSN010L -ID LG, IRR, 3 PH, BP 228
4 07APSN010S -IRR, SMALL, 3 PH 790
5 07APSNO10S -IRRIGATION 985 12,500 0794
6 07APSNS10X -IRRIGATION 123
7 07APSNL10X -IRRIGATION -
8 IRRIGATION BPA BALACCT 877 577
9 UNBILLED REV -IRRIGATION 195 213 000 0970
OR - PPL
01APSVO041-AG PMP SRVC BP 174 671 510 872 6064
01APSVO041-AG PMP SRVC BP -420,654
01APSV041L-OR Pumping Serv 148,501 988
01APSV041L-OR Pumping Serv 665,025
01APSV041T -AGR PUMP SRV 124
01APSV041T -AGR PUMP 858
01APSV041X-AG PMP SRVC 089 221
01APSV41XL-OR Pumping Serv no 122 507
01 BPADEBIT-BPA ADJUST FEE 45,886
01COSTO041 111 318 688,154 0331
01COSTS028, OR GEN SERV 207 071 0342
01GNSVO028, OR GEN SRV;:. 30 646
01HABIT041 - 01APSVO041 AG 337 0337
01LNXO0102-LlNE EXT 80% G 175
01LNXO0103-LlNE EXT 80% G 841
01LNXO0109-REF/NREF ADV +927
01LNXO0110-REF/NREF ADV +305
01NMT41135 - NETMTRAG PMP 103
29 01PTOUO041 - 01APSVO041 AG 16,519 1796
30 01RENEWO41 - 01APSVO041 AG 298 0333
31 01SLXOOO05-KLAMATH FALLS 227 770
32 01SLXOO013-K FALLS IRG MI 20,505
33 01SLXOO014-K FALLS IRG MI 833
34 01STDAY041 - Daily Standard Offer 206 0515
35 01UKRBO035-KLAMATH BASIN 45,770 343,276 683 013 0075
36 01UKRBO035-KLAMATH BASIN 222 380
37 01USBRO040-KLAMATH BASIN 391 302 342 380 36,515 0060
38 01USBRO040-KLAMATH BASIN 212,337
39 01USBR33TX-IR TOU WIO BPA 282 12,241 328,200 0037
40 01ZZMERGCR-MERGER CREDITS -41
TOTAL Billed 504,09'807 927 440 056/Total Unbilled Rev.(See Instr. 6)142 101 12,034,000 084/
TOTAL 49,646,819,961 440 056
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 2005/Q4
(2) CiA Resubmission 03/20/2006
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 Of Kate scneaUie Mvvn ~ola Kevenue Average. NumDer ~~~n?~S~;::r ~G~oNo.(a)(b)(c)of c~~\omers
(f)
1 IRRIGATION BPA BAL ACCT 189,754
2 IRRIGATION UNBILLED 132 8,000 0606
3 OR ENRGY COST RECOV AMORT 481
4 OR Irrigation - BPA adjustment 523
5 01LNXO0312 - OR IRG LINE EXT 547
6 01 GNSVO030 - OR GEN SRV, ~ 200 746
7 01NMT41135- NETMTRAG PMP
8 01COSTS030 - OR GEN SRV CBS ~
9 UT - UPL
08APSVO010-IRR & SOIL DRA 142,924 420 896 353 741 0519
08APSV10NS-lrg Soil Drain Pump N 363 422 831 152 055 0506
08LNXOOO02-MTHL Y 80% GUAR 850
08LNXOOO04-ANNUAL 80%GUAR 145
08LNXOO014-80% MIN MNTHL Y 557
08LNXOOO 17 -ADVIREF &80%ANN 66,361
08LNXO0151-AGR MTH+ADV+BT 176
08LNXO0152-AGR ANN GUAR M 200
08LNXO0153-AGR ANN+ADV+BT 328
08LNXO0310 - IRR, 80% ANNUAL 951
UNBILLED REV -IRRIGATION 000 0750
WA - PPL
02APSVO040-WA AG PMP SRVC 156 367 087 523 715 164 0581
02APSVO040-WA AG PMP SRVC 759 142
02APSV040X-WA AG PMP SRVC 149 105,884 550 816 0578
02BPADEBIT-BPA ADJUST FEE 354
02LNXO0102-LlNE EXT 80% G 197
02LNXO0103-LlNE EXT 80% G 10,809
02LNXO0105-CNTRCT $ MIN G
02LNXO01 09-REF/NREF ADV +2,447
02LNXO0110.REF/NREF ADV +72,470
02RFNDCENT - CENTRALIA RFND 642
02ZZMERGCR-MERGER CREDITS
IRRIGATION BPA BAL ACCT 123 360
34 IRRIGATION UNBILLED 216 000 0463
35 WY - PPL
36 05APSOO040-AG PUMPING SVC 14,446 070,448 544 26,555 0741
37 05LNXO011 O-REF/NREF ADV +32,844
38 05LNXO0103-LlNE EXT 80% G 142
39 05LNXO0105-CNTRCT $ MIN G 105
IRRIGATION UNBILLED 000 0141
TOTAL Billed 49,504,09~807,927,440 056
Total Un billed Rev.(See Instr. 6)142,1OE 034 000 084/
TOTAL 646,20.819,961,440 056S
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This 7!)ort Is:Date of Report Year/Period of Report
PaclfiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) Ei A Resubmission 03/20/2006
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 un billed revenue as of end of year for each applicable revenue account subheading.
line Number ana ,me or N:ate scneaUie Mvvn ;:)ola N:evenue Average. Numoer ~vvn or ~ales ~~~o~er
No.(a)(b)(c)of Cu
&i\omers
Per '(~stomer
(f)
1 05LNXO0103-LlNE EXT 80% G 165
2 05LNXO0110-REF/NREF ADV +734
3 09APSV0210-IRR & SOIL DRA 332 216 000 0647
4 Less Multiple Billings 580
6 Total Irrigation Sales - 422.176,420 271 865 22,586 52,086 0427
8 Public Street & Highway Lighting
9 CA- PPL
06COSLO052-CO-OWND STR LG 638 600 7048
06CUSL053F-SPECIAL CUST 0 462 140 531 125 696 0961
06CUSL058F-CUST OWND STR 241 253 640 1089
06HPSVO051-HI PRESSURE SO 726 146,833 429 2022
060AL T015N-OUTD AR LGT SR
UNBILLED REVENUE 000 0909
ID - UPL
07SLCOO011-STR LGT CO-OWN 137 777 724 2028
07SLCU1201-TRAF SIGNAL SY 175 13,580 333 0776
07SLCU1203-STR LGT CUST-264
07SLCU122A-STR LGT CUST -193 052 846 0417
07SLCU122B-STR LGT CUST-919 178 816 241 963 0932
UNBILLED REVENUE 000 1364
OR - PPL
01COSLO052-STR LGT SRVC C 2,428 216 736 112 679 0893
01 CUSLO053-CUS-OWNED MTRD 713 641 551 0654
01CUSL053F-STR LGT SRVC C 11,575 493 079 177 395 0426
01 HPSVO051-HI PRESSURE SO 158 660,812 664 358 1320
01 MVSLO050-MERC V APSTR LG 15,353 268,323 321 829 0826
010ALT015N-OUTD AR LGT NR 000 0990
01ZZMERGCR-MERGER CREDITS
OR ENRGY COST RECOV AMORT 176 908
UNBILLED REVENUE 000 6263
UT - UPL
34 08CFROO012-STR LGTS (CONV
35 08CFROO051-MTH FAC SRVCHG 529
36 08CFROO061-UIG AREA LIGHT 117
37 08CFROO062-STREET LIGHTS
38 08HAXTO060-LlGHTNG-HAXTON 502 000 5020
39 080ALTO07N-SECURITY AR LG 918 000 1633
08SLC1202F-TRAFFIC SIG NM 417 835 129 984 0570
TOTAL Billed 49,504 09-4 807,927 440 056
Total Unbilled Rev.(See Instr. 6)142 034 000 084/
TOTAL 49,646,20.819,961 440 056E
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 2005/Q4(2) 0 A Resubmission 03/20/2006
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 un billed revenue as of end of year for each applicable revenue account subheading.
I Line NumDer ana Iitie or Kate scneaUie Mwn ~ola I'\evenue 1\verage NumOer ~ vvn~ Or ~ales ~~folderNo.(a)(b)(c)of Cus~omers Per 9~stomer
(f)
1 08SLCOO011-STR LGT CO-OWN 865 360 399 212 991 1924
2 08SLCU1202-TRAF & OTHER S 343 366,772 536 479 0686
3 08SLCU1203-MTR OUTDONIGHT 981 181 25,816 0736
4 08SLCU121A-STR LGT CUST-897 101 369 366 40,702 0739
5 08SLCU121B-STR LGT CUST-23,362 731 970 275 84,953 0741
6 08SLD13ES1-DECOR CUST-OWN 301 242,113 153,683 0384
7 08SLD13ES2-DECOR CUST -OWN 343 281 882 166 886 0384
8 08SLD13FS1-DECOR CaMP-OWN 162 000 1757
9 08SLD13FS2-DECOR COMP-OWN 240 107,493 20,000 4479
08SLD13MS 1-DECOR CUST -OWN 879 73,589 58,600 0837
08SLD13MS2-DECOR CUST-OWN 072 109 755 667 1024
08THIKO077-STR LIGHT SPEC 141 277 141,000 1225
08ZZMERGCR-MERGER CREDITS
UNBILLED REVENUE 149 280,000 0889
WA - PPL
02CFROO012-STR LGTS (CONV
02COSLO052-WA STR LGT SRV 481 205 864 0940
02CUSL053F-WA STR LGT SRV 941 202 012 178 140 0513
02CUSL053M-WA STR LGT SRV 950 56,094 728 0590
02HPSVO051-WA HI PRESSURE 092 462,664 142 21,775 1496
02MVSLO057-WA MERC VAPSTR 554 223,512 540 0875
02RFNDCENT - CENTRALIA RFND 346
UNBILLED REVENUE 000 6364
WY - PPL
05COSLO057 -CO-OWND STR LG 616 104,225 18,118 1692
05CUSL058F-CUST OWND STR 335 757 667 0560
05CU5L058M-CUST OWND STR 145 375 0553
05HPSVO051-HI PRESSURE SO 705 713,797 181 994 1517
05MVSOO053-MERCURY VAPOR 099 489,403 288 705 0960
09SLCO0211-STR LGT CO-OWN 410 000 2050
09SLCU2122-TRAF & OTHER S 223 000 0372
UNBILLED REVENUE 698 83,000 1189
WY - UPL
09SLCO0211-STR LGT CO-OWN 300 427,379 444 3288
09SLCU2121-STR LGT CUST-517 214 1669
09SLCU2122-TRAF & OTHER 5 2,416 929 0350
UNBILLED REVENUE 000 2921
Less Multiple Billings 460
Total Public Street & Hwy - 444 165 692 038 050 271 38,795 1028
TOTAL Billed 49,504,0g../807 927,440 0567
Total Unbilled Rev.(See Instr. 6)142 034 000 0847
TOTAL 646,20.819,961 440 056
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 2005/Q4(2) DA Resubmission 03/20/2006
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.
luna Numcer ana Iltia or Kate scneaUie Mvvn :soia Kevenue Iwerage Numcer ~vvn oT ~ales ~~~folderNo.(a)(b)(c)of cus~omers Per ~~stomer
(f)
2 Other Sales to Public Authorities
3 UT - UPL
4 08GNSVOOO6-GEN SRVC-DISTR 16,547 776 757 757 833 0469
5 08GNSVOO09-GEN SRVC-HI VO 309 85,947 309,000 0372
6 08GNSVO023-GEN SRVC-DISTR 298 250 0705
7 08GNSVO09M-MANL HIGH VOLT 436,032 16,191,271 109,008,000 0371
8 080AL TO07N-SECURITY AR LG 575 000 1830
9 08GNSVOO08 - UT GEN SVC TOU :-14,926 649,028 14,926 000 0435
UNBILLED REVENUE 574 358,000 0374
Less Multiple Billings
Total Other Sales to Public Auth.460,326 353,876 227 684 0377
Forfeited Discounts
CA - PPL
Late Fees 177 875
ID - UPL
Late Fees 223,208
OR - PPL
Late Fees 034 971
UT - UPL
Late Fees 286,699
WA - PPL
Late Fees 400 881
WY - PPL
Late Fees 359,490
WY - UPL
Late Fees 52,121
Total Forfeited Discounts - 450 535 245
Miscellaneous Service Revenues
CA - PPL
06CFROOO03-MTH MAINTENANC 1,454
06CONN0300-CA RECONNECTIO 27,824
06RCHK0300-CA RET CHK CHR 648
06TAMP0300-CA TAMP & UNAU 967
06TEMP0300-CA TEMP SRVC C 15,555
06XTNTHEFT - TAMPER & RECON 123
TOTAL Billed 49,504,094 807 927 440 0561
Total Unbilled Rev.(See Instr. 6)142,10e 034 000 0847
TOTAL 49,646,20;./819.961,440 056
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~ort Is:Date of Report YearlPeriod of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
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 un billed revenue as of end of year for each applicable revenue account subheading.
LIne Numcer ano I me OT t(aIe scneoUie Mvvn ;)010 t(evenue Average. Numcer ~WIJ..OT :;iales ~WR~olderNo.(a)(b)(c)of C~~\omers Per r~stomer
(f)
1 Energy Finanswer new Com 665
2 Home Comfort 901
3 Industrial Finanswer 522
4 Irrigation Finanswer 812
5 weatherization Loans 8%
6 Other 3,470
7 06SRVCHARG-EXCESS FOOTAGE 136,383
8 ID - UPL
9 07CFROOO01-MTH FAC SRVCHG 101
07CONN0300-ID RECONNECTIO 050
07FCBUYOUT - FAC CHG BUYOUT 848
07RCHK0300-ID RET CHK CHR 810
07T AMP0300 650
07TEMPO014-TEMP SRVC CONN 25,445
Energy Finanswer new Com 137
Weatherization Loans ID 048
07SRVCHARG-EXCESS FOOTAGE 277
07XTNTHEFT - TAMPER & RECON 261
OR - PPL
01CFROOO03-MTH MAINTENANC 139
01CFROO013-MTH MISC CHRG 513
01CFROO014-YR MISC CHRG
01 CONN0300-RECONNECTION C 828 695
01 ESSC0600 - ESS charges 974
01 FCBUYOUT-FAC CHG BUYOUT 212
01HAFGO011-HSLE FREE GUAR
01 MISCOOOO-FEE OFFERING N
01MTRVR300-METR VERIF FEE 280
01 RCHK0300-RETURNED CHECK 194,705
01TAMP0300-TAMP & UNAUTH 23,250
01TEMP0300-TEMP SRVC CHRG 390 130
01TRBL0300-TROUBLE CALL C
01XTNTHEFT - TAMPER & RECON 8,427
Irrigation Finanswer 257
Misc Serv-Acct Serv Chrg -454
Other 141
01 DPAC0300-DEMAND PULSE 000
01FHFGO011-FROZEN HSLE FR
UT - UPL
08CFROO013-MTH MISC CHRG 147 885
TOTAL Billed 49,504,094 807,927 440 056
Total Un billed Rev.(See Instr. 6)142 10a 034,000 084
TOTAL 646,20~819,961,440 056
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 2005/04
(2) D A Resubmission 03/20/2006
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 un billed revenue as of end of year for each applicable revenue account subheading.
Number ana Ime Of t\ate scneoule Mvvn ;)010 t\evenue I\verage Numcer ~~~n
9~s ~:r ~G~olderNo.(a)(b)(c)of C~~\omers
(f)
1 08CFROO051-MTH FAC SRVCHG 1 B5,094
2 08CFROO052-ANN FAC SVCCHG 424
3 OBCFROO056-MTH EOUIP RENT 101
4 08CFROO063-MTH MISC CHARG 316
5 08CFROOO64-ANN MISC CHARG 660
6 08CONN0300-RECONN&DISCONN 850,392
7 08FCBUYOUT-FAC CHG BUYOUT 234,440
8 08INFO0300-CUST/3RD P REO
9 OBMTRVR300 - Meter Verification F
08NCON0300-UT FEE NRES RE 428
OBRCHK0300-UT RET CHK CHR 230,730
08RCONOO01-CONNECT FEE 811 178
OBSPCLOO07-SPECL FAC CHRG 25,000
08T AMP0300- T AMPERING&UNAU 29,250
08TEMPO014-TEMP SRVC CONN 934 065
08XTNTHEFT - TAMPER & RECON 134
Energy Finanswer 12 000 7B8
Energy Finanswer new Com 132,306
Other 776
08SRVCHARG-EXCESS FOOTAGE 509,951
Misc Serv-Acct Serv Chrg 167
08VISIT300 - UT Visit, Service Ca 645
Retrofit Finanswer 110
WA - PPL
02CFROOOO3-MTH MAINTENANC 320
02CONN0300-WA RECONNECTIO 157 045
02FCBUYOUT - FAC CHG BUYOUT 957
02RCHK0300-WA RET CHK CHR 350
02TAMP0300-WA TAMP & UNAU 275
02TEMP0300-WA TEMP SRVC C 720
02XTNTHEFT - TAMPER & RECON 599
Energy Finanswer new Com 9,492
Home Comfort 082
34 Industrial Finanswer 750
35 Other 238
36 02SRVCHARG-EXCESS FOOTAGE 85,275
37 WY - PPL
38 05CFROOO03-MTH MAINTENANC 032
39 05CFROO013-MTH MISC CHRG 186
05CONN0300-WY RECONNECTIO 5B,550
TOTAL Billed 49,504,09'807,927 440 056/
Total Un billed Rev.(See Instr. 6)142 1DE 12,034 000 084/
TOTAL 49,646,819,961 440 056E
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 2005/Q4
(2) n A Resubmission 03/20/2006
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.
ILine ' NUmcer ana Iltle or t(ate scneaule Mvvn ~ola t(evenue Average. Numcer ~~n~~sr;::r ~W~folderNo.of Cus~omers(a)(b)(c)(f)
1 05FCBUYOUT - FAC CHG BUYOUT 23,065
2 05RCHK0300-WY RET CHK CHR 610
3 05SERV0300-WY SRVC CALLS 800
4 05TAMP0300 200
5 05TEMP0300-WY TEMP SRVC C 645
6 Energy Finanswer new Com
7 Other
8 05LONGFORM-BILL PRINT
9 05SRVCHARG-EXCESS FOOTAGE 843
05XTNTHEFT - TAMPER & RECON 500
WY - UPL
05CONN0300-WY RECONNECTIO 555
05FCBUYOUT - FAC CHG BUYOUT 103 238
05RCHK0300-WY RET CHK CHR 070
05SERV0300-WY SRVC CALLS 120
05T AMPO300 150
05TEMP0300-WY TEMP SRVC C 335
05XTNTHEFT - TAMPER & RECON
09CFROOO01-MTH FAC SRVCHG 831
09CFROO014-YR MISC CHRG
Energy Finanswer 12,000 637
Less Multiple Billings
Total Misc. Servo Rev. - 451 681 519
Rent from Electric Property
CA - PPL
06CFROOO06-MTH RNT AL CHRG 647
RENT REVENUE-HYDRO 204 750
RENT REV-TRANSMISS
06CFROOO02-ANN FAC SVCCHG 207
Rent Revenue - Subleases 000
Joint use 901 574
ID - UPL
07CFROOO09-YR LSE CHRG-794
07INVCHGOO-INVEST MNT CHG 183
07LOOPO014-MTH FEE PRE-921
07POLEO075-STEEL POLES US 302
07XTRNO013-RNT/LSE L& PRO 103 108
RENT REVENUE-HYDRO 600
TOTAL Billed 49,504,09~807,927 440 0567
Total Un billed Rev.(See Instr. 6)142,10E 034 000 084/
TOTAL 646 20.819,961 440 056E
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 2005/Q4(2) 0 A Resubmission 03/20/2006
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.
Lome Numcer ana Iitie or Kate scneoUie Mwn ::soia Kevenue Average, Numcer Ilvvn, or ~ales ~6folderNo.(a)(b)(c)of cu(~\omers Per 9~stomer
(f)
1 Joint use 547,048
2 OR - PPL
3 01CFROOOO6-MTH RNTAL CHRG 594,283
4 (454)240,264
5 (454) Non Common 22,264
6 (454)352 174
7 RENT REVENUE-HYDRO 495
8 RENT REV-TRANSMISS 603
9 RENT REV-DISTRIBUT 549
RENT REV-GEN(COMM)623
01XTRNO013-RNT/LSE L& PRO 800
Joint use 630,028
UT - UPL
08CFROO058-MTH EQUIP LEAS 733,710
08INVCHGON-INVEST MNT CHG 691
08INVCHGOR-INVEST MNT CHG 345
08LOOP014N-TEMP SERV CONN 20,690
08POLEOO04-POLE A TT ACHMEN 4,437
08POLEO075-STEEL POLES US 91,511
08XTRNO013-RNT/LSE L& PRO 75,184
(454)768
(454) Non Common 5,434
RENT REVENUE-STEAM 133 977
RENT REVENUE-HYDRO 142 676
RENT REV-TRANSMISS 453 230
RENT REV-DISTRIBUT 66,102
RENT REV-GEN(COMM)450,152
Joint use 327 547
WA - PPL
02CFROOO01-MTH FACILITY S 281
02CFROOO06-MTH RNT AL CHRG 42,492
RENT REVENUE-HYDRO 524,183
RENT REV-DISTRIBUT 884
RENT REV-GEN(COMM)38,421
RENT REV-TRANSMISS 250
Rent Revenue - Subleases 15,650
Joint use 176 183
WY - PPL
05CFROOO01-MTH FACILITY S 524
05CFROOO06-MTH RNTAL CHRG 944
TOTAL Billed 49,504 09~807 927,440 0567
Total Unbilled Rev.(See Instr. 6)142 034,000 0841
TOTAL 646,20.819 961,440 0561:
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PaclfiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) nA Resubmission 03/20/2006
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 un billed revenue as of end of year for each applicable revenue account subheading.
iLine NumDer ana I !tie 01 Kate scneaUie Mvvn ;)010 Kevenue 1\verage NumDer ~vvn oT ~ales 'i~~~o lderNo.(a)(b)(c)of C~~\omers Per C(~stomer
(f)
1 RENT REVENUE-STEAM 32,256
2 RENT REV-TRANSMISS 550
3 RENT REV-GEN(COMM)12,739
4 (454) Non Common 100
5 RENT REV-DISTRIBUT 275
6 Rent Revenue - Subleases 142
7 Joint use 653,590
8 WY - UPL
9 09LOOP0214-MTH FEE PRE-485
09POLEO075-STEEL POLES US 21,371
RENT REVENUE-STEAM 5,468
Joint use -401 613
Total Rent from Elec. Prop. - 45 523 564
Other Electric Revenues
WHEELING ESTIMATE 70,768
OTH ELEC ESTIMATE 415 529
GREEN CREDIT SALES 393,945
Other Elec (exclud Wheel)925 307
Post Merg Firm Wheeling 765,046
OTH ELEC REV - TRANS ANC 844 921
Fish, Wildlife, Recr 190
Inter-Co Other Elec Reve 738,875
Pre Merg Firm Wheel PPL 949,666
Pre Merg Firm Wheel UPL
CA - PPL
Fish, Wildlife, Recr 812
ID - UPL
Fish, Wildlife, Recr 140
Other Elec (exclud Wheel)891,584
OR - PPL
01CFROOO01-MTH FACILITY S 866
01CFROOO04-EMRGNCY ST&BY 393
01CFROOO05-INTERMTNT SRVC 42,247
36 SVC PRVD OTHERS-REV 171 240
37 INTERCO FIRM WHEEL 282 886
38 INTERCO NON-FRM WHEEL 738,236
39 Non-Firm Wheeling 13,289,509
Other Elec (exclud Wheel)28,803 339
TOTAL Billed 504,09~807,927,440 056
Total Unbilled Rev.(See Instr. 6)142 034 000 084,
TOTAL 49,646,20~819 961,440 056f
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 2005/Q4(2) n A Resubmission 03/20/2006
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 un billed revenue as of end of year for each applicable revenue account subheading.
ILlne NumDer ana IlIIe or Kate scneaUie Mvvn ~ola Kevenue I'\verage , NumDer ~vvn OT ;;:.ales ~WWg'o lderNo.(a)(b)(c)of C~~\omers Per ?~stomer
(f)
1 Other Elec DSR carry chrg 561 113
2 Post Merg Firm Wheeling 321 349
3 Pre Merg Firm Wheel PPL 659 696
4 Pre Merg Firm Wheel UPL 420 370
5 Rec Wheeling Rev 000
6 Short-term Firm Wheeling 030 875
7 01LPAY0300-LATEFEE
8 OTH ELEC REV - TRANS ANC 102
9 Inter-Co Other Elec Reve 259 605
INTERCO Short-Term WHEEL 267,240
UT - UPL
08CFROO053-MTHL Y MAINTFEE 619
08XTRNO016-0UTBIL SVC REN 204,201
(456.)ELEC INC-OTHR 328,690
FL YASH SALES 183 853
DSM REV-UT SBC OFFSET 30,742 167
Fish, Wildlife, Recr 465
Other Elec (exclud Wheel)311
08XTRNO018-BAL SUM MASTER 780
WA - PPL
02CFROOO04-EMRGNCY ST &BY 497
02CFROOO05-INTERMTNT SRVC 180
Fish, Wildlife, Recr 506
Other Elec (exclud Wheel)722 299
Other Elec DSR carry chrg 786
Wash Colstrip 3 52,188
WY - PPL
05CFROOO04-EMRGNCY ST&BY 638
05CFROOO05-INTERMTNT SRVC 10,454
09CFROOOO5-INTERMTNT SRVC 339
ELEC INC-OTHR 331 101
FL YASH SALES 890 980
Other Elec (exclud Wheel)971
FLY ASH SALES 436
Total Other Electric Rev. - 456 141 480 032
TOTAL Billed 49,504 807 927 440 0567
Total Un billed Rev.(See Instr. 6)142,1OE 12,034 000 0847
TOTAL 646,20.819 961 440 056E
FERC FORM NO.1 (ED. 12-95)Page 304.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) OA Resubmission 03/20/2006
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 fIling Avera AveracationTariff Number Demand (MW)Monthly NC Deman!Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Brigham City 18.18.17.
Deaver, Town of T-4
3 Helper City
Helper City Annex
5 Navajo Tribal Utility Authority (Mexica
6 Navajo Tribal Utility Authority (Red Me
7 Portland General Electric Co.147
8 Portland General Electric Co.147
9 Price City 12.12.11.
Accrual True-up
American Electric Power WSPP
Arizona Public Service Co.lI':,
Arizona Public Service Co.
Arizona Public Service Co.
Subtotal RQ
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
PaclfiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2) D A Resubmission 03/20/2006
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.
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 average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (t) 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-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)
(j)
(k)
109,284 682,213 903,727 585 940
986 907 762 669
863 104 196 103,837 208 033
631 68,083 64,310 132 393
066 355 18,574 929
251 85,151 91,463 176,614
387
056 917,983 917 983
845 116,658 252,484 369,142
715
~/"/\' ,' "?""''"
76,314
239 800 15,414 200 15,414 200
96,175 818,105 818 105
377 388 141 388 141
060,707 59,929,918 59,929,918
208,189 090,563 370,140 927 388 776
13,066,252 091 965 419 005,348 867 448,811 608 648 502
13,274,441 60,182,528 423,375,488 -867,520,738 616,037 278
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 2005/Q4
(2) 0 A Resubmission 03/20/2006
SALES FOR RESALE (Account 4
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 IIlIng . !\vera AvercationTariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Avista Corp.WSPP
2 Avista Corp.
3 Avista Corp.WSPP
4 Avista Energy, Inc.WSPP
5 Avista Energy, Inc.
6 Avista Energy, Inc.wspp
7 BP Energy Company
B BP Energy Company WSPP
9 Basin Electric Power Cooperative
Basin Electric Power Cooperative
Basin Electric Power Cooperative WSPP
Basin Electric Power Cooperative
Basin Electric Power Cooperative WSPP
Benton County Public Utility District N WSPP
Subtotal RQ
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent
PaciflCorp
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 03/20/2006
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (t) 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 2005/Q4
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
150 925
107 071
240 393,529
475
264 19,262
320,330 023,174
2,435 185,976
234,795 191 237
253 237 141
117 6,435
143 982
620 389 474 389,47
586 530,110 530,110
208 189
13,066,252
090,563
091 965
370,140
419,005,348
71,927
867 448,811
388 776
608 648 502
13,274,441 60,182,528 423,375,488 867,520,738 616,037,278
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent I his 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., 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 f\vera Avera
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Black Hills Power, Inc.236 50.50.47.
Black Hills Power, Inc.WSPP
3 Black Hills Power, Inc.WSPP
Blanding City
5 Bonneville Power Administration
6 Bonneville Power Administration
7 Bonneville Power Administration 543
Bonneville Power Administration
Bonneville Power Administration 370
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration WSPP
British Columbia Transmission Corp.
Subtotal RQ
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This (ID'ort Is:Date of R~ort Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, r)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
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.
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 average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (t) 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-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 ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(9)(h)(i)
(j)
(k)
364,452 119,761 992 653 112,414
425 322 545 322 545
136,754 889 521 889,521
12,877 180,000 333 503 513 503
980 "i'
""".""
200,672
106,045
472 701 19,380,741 19,380,741
39,743 667 616 667 616
650
:..
178
542 904
096
046
061 831 164 831 164
291
"",
",Y'"
--:-'",..
208,189 090,563 370 140 927 388 776
13,066,252 091 965 1,419 005 348 867 448 811 608 648,502
13,274,441 60,182,528 1,423,375,488 867,520,738 616,037,278
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 2005/Q4(2) n A Resubmission 03/20/2006
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 . ~vera AvercationTariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Burbank, City of WSPP
Burbank, City of WSPP
3 Califomia Independent System Operator .;"FF
California Independent System Operator
5 Calpine Energy Services, loP.
Cargill Power Markets, LLC
Cargill Power Markets, LLC
Cargill Power Markets, LLC
9 Cargill Power Markets, LLC
Chelan County Public Utility District WSPP
Citigroup Energy, Inc.
Clark Public Utilities
Clark Public Utilities t....:
).
Clatskanie Peoples Utility District WSPP
Subtotal RQ
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) n A Resubmission 03/20/2006
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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (t) 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.
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2005/04
MegaWatt Hours
Sold
(g)
Demand Charges
($)
(h)
REVENUE
Energy Charges
($)
(i)
Other Charges
($)
Total ($)
(h+i+j)
(k)
Line
No.
119,416
062
787,132
390
586
151,421
800
181 015
444
332 412
45,452,023
444
332,412
404,458
45,452 023
200
198,845
185 272
231 963
300
13,965,091
280,694
19,931 146
375
185,272
231 963
37,300
13,965,091
363,864
030
119 162 811 984
375
208,189
13,066,252
090,563
091,965
370,140
419,005,348
927
867 448 811
388 776
608,648 502
13,274 441 60,182,528 423,375,488 867 520,738 616,037,278
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 2005/Q4(2)D A Resubmission 03/20/2006
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 mustbe 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" meansLonger 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 1\vera AveragecationTariff Number Demand (MW)Monthly NC Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Colorado River Commission of Nevada WSPP
2 Colorado Springs Utilities WSPP
3 Colorado Springs Utilities WSPP
4 Conoco Inc.
5 Constellation Energy Commodities Group,Ii"".,.;"," 77'
6 Constellation Energy Commodities Group,
7 Coral Power WSPP
8 Coral Power WSPP
9 Cowlitz County Public Utility District 234
Deseret Generation & Transmission
Douglas County Public Utility District WSPP
Duke Energy Trading & Marketing, LLC
ENMAX Energy Marketing Inc.WSPP
EPCOR Merchant and Capital Inc. WSPP
Subtotal RQ
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 2005/Q4
(2) n A Resubmission 03/20/2006
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 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (t) 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 ,line 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)
(j)
(k)
225 589 694 589 694
644 172 747 172 747
728 534,408 534,408
142 122 592 982 592 982
040 43,050 43,050
171,912 66,294 314 294 314
150 300
873 409 95,119 377 120 089
132,144 671 504 671,504
105 Vr';;r""r"'c;;'
;;'
614
212 9,443 443
369 918 13,983,193 13,983 193
1,478 99,835 99,835
316 201 212 201 212
208,189 090,563 370,140 71,927 388,776
13,066,252 57,091,965 419,005,348 867 448,811 608 648 502
13,274,441 60,182,528 423,375,488 867 520,738 616,037,278
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 2005/Q4(2) 0 A Resubmission 03/20/2006
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i., 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 , ~vera AveracationTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 EI Paso Electric Company WSPP
EI Paso Electric Company WSPP
Eugene Water & Electric Board """cf\ ,
',,
Eugene Water & Electric Board WSPP
5 FPL Energy Power Marketing, Inc.WSPP
6 Flathead Electric Cooperative
Franklin County Public Utilities Distri WSPP
8 Glendale, City WSPP
9 Grant County Public Utility District No WSPP
Grays Harbor Public Utility District WSPP
Hurricane, City of FLt-':::h
Idaho Falls, City of WSpp
Idaho Power Company
+:;,,
Idaho Power Company WSPP
Subtotal RQ
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 2005/Q4(2) n A Resubmission 03/20/2006
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 average
monthly coincident peak (CP)
demand in column (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (t) 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-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)
(j)
(k)
465 24,475
" "
:315 790
060 027 395 027 395
:' :';...
575
529 553,248 553 248
582 577 150 577 150
149 146 167 969 167 969
291 265 803 265,803
400 700 700
18,477 200,422 200,422
023 461 000 461 000
20,703 579,684 579,684
400 19,200 200
219 )i" "
' '
152 842
; '
c'"
238 92,4001";:
"'" "
:4,75C 97,150
208,189 090 563 370 140 927 388 776
13,066,252 091 965 419,005,348 867,448,811 608,648 502
274,441 60,182,528 423,375,488 867 520,738 616,037 278
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 2005/Q4(2) 0 A Resubmisslon 03/20/2006
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., 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:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., 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 /'\vera AvercationTariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Idaho Power Company
2 Idaho Power Company
3 Idaho Power Company WSPP
4 J. Aron & Company
5 J. Aron & Company
6 Los Angeles Dept. of Water & Power 301
7 Los Angeles Dept. of Water & Power WSPP
8 Los Angeles Dept. of Water & Power WSPP
Merrill Lynch Commodities, Inc.WSPP
Metropolitan Water District WSPP
Modesto Irrigation District WSPP
Morgan Stanley Capital Group, Inc.11:: ':' i;"";C;,
Morgan Stanley Capital Group, Inc.
Morgan Stanley Capital Group, Inc.
Subtotal RQ
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 2005/Q4
(2)0 A Resubmission 03/20/2006
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 ot the contract and service from designated units ot 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 ot 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 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 (t). For all other types ot service, enter NA in columns (d), (e) and (t). 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 (t) 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 ot charges, including
out-ot-period adjustments, in column 0). Explain in a footnote all components ot 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.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
10,092 661 923
138
,"":':"
got,!711
208,514 117,636 117,636
442
707,604 608,767 608 767
556,965 042 351 042,351
13,419 617 504 617 504
297 318 15,795,633 15,795,633
68,779 448,190 448,190
075 815,525 815 525
14,880 260,980 260 980
96,191 819,033 819,033
212
."""
235,752
293 302 219,590,319 219 590 319
208,189 090,563 370,140 71,927 388 776
13,066,252 091 965 419,005,348 867,448,811 608,648,502
13,274,441 60,182,528 423,375,488 867,520,738 616,037,278
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 2005/Q4(2) 0 A Resubmission 03/20/2006
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 !\vera AvercationTariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Municipal Energy Agency of Nebraska WSPP
Nevada Power Company WSPP
NorthWestem Energy
Northem Califomia Power Agency WSPP
5 PPL Energy Plus, LLC OS'
", ,
WSPP
6 PPL Energy Plus, LLC WSPP
7 PPL Montana, LLC
8 PPL Montana, LLC WSPP
9 PPL Montana, LLC
PPL Montana, LLC WSPP
----,':
14 Pacific Northwest Generating Cooperativ WSPP
Subtotal RQ
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 2005/Q4(2) 0 A Resubmission 03/20/2006
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 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 (t). For all other types of service , enter NA in columns (d), (e) and (t). 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 (t) 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.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
241 537 319 537 319
50,121 099,903 099 903
472
~,,
724
018 474 602 474 602
500 500
43,297 872 565 872 565
366 18,251
007
065 111 397
41,520 2,473 945 473,945
107 600
745 ii!; 36,592
660
'.'
729,084
268 725,845 725 845
208,189 090,563 370,140 927 388 776
13,066 252 57,091,965 419,005,348 867,448,811 608,648,502
13,274,441 60,182,528 423,375,488 867,520,738 616,037,278
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 2005/Q4(2) 0 A Resubmission 03/20/2006
SALES FOR RESALE (Account 4
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 iIIing Avera AveracationTariff Number Demand (MW)Monthly NC Deman Monthly CP em and
(a)(b)(c)(d)(e)(f)
1 Panda Gila River WSPP
Pinnacle West Capital Corporation
Portland General Electric Co.
Portland General Electric Co.
5 Portland General Electric Co.
Portland General Electric Co.
7 Powerex
Powerex
Powerex
Powerex WSPP
Powerex wspp
Public Service Company of Colorado
'iii
320
Public Service Company of Colorado 320 176.176.176.
Public Service Company of Colorado
Subtotal RQ
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent
PacifiCorp
This ~ort Is: Date of Report(1) I.!JAn Original (Mo, Da, Yr)
(2) A Resubmission 03/20/2006
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 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (t) 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 2005/Q4
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
500 381 945 381 945
380 688 25,965 456 25,965,456
765
791
312 400 18,477 213
626
345 116 144
16,916 900 613
998 846 509
610 257 076
101 986 644,861
884
162 141 646,080 622 709
10,488 267,791
208,189
13,066,252
090,563
091 965
370,140
1,419,005,348
927
867 448,811
388,776
608 648,502
13,274,441 60,182,528 423,375,488 867,520,738 616,037,278
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 2005/04(2) 0 A Resubmlssion 03/20/2006
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., 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 lliing Avera Avera
cation Tariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Public Service Company of Colorado
"'~';""
WSPP
Public Service Company of Colorado WSPP
3 Public Service Company of New Mexico "'1!'1,
"::,:::
WSPP
4 Public Service Company of New Mexico WSPP
5 Puget Sound Energy WSPP
6 Puget Sound Energy
7 Puget Sound Energy WSPP
8 Rainbow Energy Marketing WSpp
9 Rainbow Energy Marketing
Rainbow Energy Marketing WSPP
Redding, City of WSPP
SUEZ Energy Marketing NA, Inc.WSPP
Sacramento Municipal Utility District 250
Sacramento Municipal Utility District 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 2005/04(2) n A Resubmission 03/20/2006
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.
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 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 (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 (t) 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 RQ/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)
373 452 732 452 732
649,513 39,437 246 39,437 246
988 934 546 I""'
,' "'/,
P~~li 943,486
407,931 862 743 22,862 743
:,'
780
052
202 033 184 3711;"
~./.
198,571
127 725 725
141 113,900
790 426,190 426,190
097 711 516 711,516
163,781 560 685 560,685
'i','
, ',,;
172 599
;..,/, ,
M4a -48
" "
208,189 090,563 370,140 927 388,776
13,066,252 091 965 419,005,348 867 448,811 608,648 502
13,274,441 60,182,528 423,375,488 867 520,738 616,037 ,278
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 2005/Q4(2) n A Resubmission 03/20/2006
SALES FOR RESALE (Account 4
1. Report all sales for resale (Le., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
i power exchanges during the year. Do not report exchanges of electricity ( Le., transactions involving a balancing of debits and credits
j for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on theI 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 lliing 1\vera Aver
cation Tariff Number Demand (MW)Monthly NC Deman Monthly C mand
(a)(b)(c)(d)(e)(f)
1 Sacramento Municipal Utility District 250
2 Sacramento Municipal Utility District WSPP
3 Salt River Project WSPP
4 Salt River Project WSPP
5 San Diego Gas & Electric WSPP
6 Santa Clara, City of WSpp
7 Seattle City Light
8 Seattle City Light WSPP
9 Sempra Energy Resources
Sempra Energy Solutions WSPP
Sempra Energy Trading Corp.
Sempra Energy Trading Corp.
Sierra Pacific Power Company 258
Sierra Pacific Power Company ~:T:"
Subtotal RQ
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 2005/Q4
(2) 0 A Resubmission 03/20/2006
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 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;!ln 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (t) 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.
MegaWatt Hours REVENUE Line
Sold Demand Charges Energy Charges Other Charges Total ($)
($)($)($)
(h+i+j)No.
(g)
(h)(I)(k)
523,885 052 733 052 733
102 608 387,056 387 056
17,383 014 491 1 ,015,616
169 293 975 638 975,638
6,442 539,122 539 122
528 1,431 894 431 894
I;;;590
741 331 037 331 037
911 256 256 256,256
18,920 215 380 215,380
156
;;,;;'
i/?'
;;," """"
119,522
287 887 111 105,741 111 105 741
, """, ,
:59~~598,034
100 'iE,
:;,
t8A~!.l6~061
208,189 090,563 370,140 927 388,776
13,066 252 57,091,965 1,419,005 348 867 448 811 608,648,502
13,274 441 60,182,528 423,375,488 867,520,738 616,037,278
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 2005/Q4(2) n A Resubmission 03/20/2006
SALES FOR RESALE (Account 4 7)
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 , t\vera AveracationTariff Number Demand (MW)Monthly NC Deman Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Sierra Pacific Power Company 258 75.75.73.
Sierra Pacific Power Company
Sierra Pacific Power Company WSPP Nil
Sierra Pacific Power Company
5 Sierra Pacific Power Company
Sierra Pacific Power Company WSPP
7 Snohomish Public Utility District No.WSPP
8 Southem Califomia Edison Company I'Lor" ' c'248
9 Southem California Edison Company
Southwestem Public Service Company WSPP
State of Califomia Department of Water
~+,
311
Tacoma, City of WSPP
TransAlta Energy Marketing Inc.I-n.o;:"
, '
WSPP
TransAlta Energy Marketing Inc.
Subtotal RQ
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This
wort
Is:Date of Report YearlPeriod of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 03/20/2006
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 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), 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 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (t) 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.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)
(9)(h)(i)(k)
459,900 15,534 000 068 341 602 341
1 ,439
~!:~
96,224
660 762 018 762 018
63,270
~:~
3,482,600
213
234 551 15,421,170 15,421 170
753 305,890 305,890
982 400 58,944 000 58,944,000
23,199 526 387 526 387
35,650 786,550 786 550
034 950
195 288,220 288,220
600 600
, i,i ii"
" '
1;744 744,i.
208,189 090,563 370 140 927 388 776
066,252 091 965 1,419 005,348 867 448 811 608 648 502
13,274,441 60,182,528 423,375,488 867 520,738 616,037,278
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 2005/04
(2) 0 A Resubmission 03/20/2006
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:
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 , ~vera AvercationTariff Number Demand (MW)Monthly NC Deman Monthly C emand
(a)(b)(c)(d)(e)(f)
1 TransAlta Energy Marketing Inc.WSPP
2 Tri-State Generation & Transmission WSPP
3 Tn-State Generation & Transmission
4 Tn-State Generation & Transmission WSPP
5 Tucson Electric Power :t':r.'WSPP NJ!
6 Tucson Electric Power WSPP
7 Turlock Irrigation District WSPP
8 UBS Warburg Energy LLC
9 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 36.36.35.
Subtotal RQ
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PaclfiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
SALES FOR RESALECAccount 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 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (t) 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.
MegaWatt Hours REVENUE Total ($)Line
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(i)(k)
856,328 269 997 269,997
562 199 163 199 967
526
99,809 33,947 500,789 534,736
610 230 36,230
419 6,456,691 456,691
15,784 321 395 321 395
894 726 749,998
;" +;""""""",;.
b4iW 745,776
17,520 665,760 665,760
571 072 072
~~=
612
762 427 713 427 713
26,021 793,440 543 318 336 758
228 743 665,575 315,987 981 562
208,189 090 563 370,140 927 388,776
13,066,252 091,965 1,419 005 348 867 448 811 608 648,502
13,274,441 60,182,528 423,375,488 -867,520,738 616,037,278
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PaclfiCorp (1) An Original (Mo, Da, Yr)End of 2005/04
(2)0 A Resubmission 03/20/2006
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., 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 (i.e., 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 , ~vera AvercationTariff Number Demand (MW)Monthly NC Deman!Monthly C emand
(a)(b)(c)(d)(e)(f)
1 Utah Municipal Power Agency
2 Utah Municipal Power Agency
3 Westem Area Power Administration
4 Westem Area Power Administration WSPP
5 Westem Area Power Administration
6 Westem Area Power Administration
7 Westem Area Power Administration WSPP
8 Weyerhaeuser ~"i,
9 Williams Energy Market & Trading Co.
Bookout Sales l'ADij,
;+'
Bookout Sales
Test Generation
Trade Sales
..,..
Trade Sales r-c,
Subtotal RQ
Subtotal non-
Total
FERC FORM NO.1 (ED. 12-90)Page 310.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
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 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sgles For Resale on Page
401 ,iine 24.
10. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE LineTotal ($)
Sold Demand Charges Energy Charges Other Charges (h+i+j)No.
($)($)($)(g)
(h)(I)(k)
llib'449I'S;;,
228 950 950
:-"
41,029 938,955 938,955
;".' "":""
249
", "
sA'T1 187"i'
"",, ".."
125 659 727 844 727 844
092 384 172
12,496 861,448 861,448
245 593
328,077 687,460,471
97,496 060,923
.""" ,"
-420
J'":\:126,453 427
208,189 090,563 370,140 927 388,776
13,066 252 091 965 1,419,005 348 867 448,811 608,648 502
13,274,441 60,182,528 423,375,488 867,520,738 616,037,278
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This fgjort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) r=; A Resubmission 03/20/2006
SALES FOR RESALE (Account 4
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 i\ling Avera AveracationTariff Number Demand (MW)Monthly NC Deman!Monthly CP emand
(a)(b)(c)(d)(e)(f)
1 Accrual True-up
Subtotal RQ
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 2005/Q4(2) 0 A Resubmission 03/20/2006
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 (t). For all other types of service, enter NA i!,!columns (d), (e) and (t). 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 (t) 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-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)
(j)
(k)
116,758 ?ri 52,809 251
:'.
208,189 090,563 370 140 927 388 776
066 252 091,965 1,419,005,348 867 448,811 608,648,502
13,274,441 60,182,528 423,375,488 867 520,738 616,037,278
FERC FORM NO.1 (ED. 12-90)Page 311.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp 12) A Resubmission 03/20/2006 2005/04
FOOTNOTE DATA
Line No.Column:
firm transactions.
Line No.Column: j
Line No.Column:
Line No.Column:
Line No.Column: b
Line No.Column:
Line No.Column: j
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 03/20/2006 2005/Q4
FOOTNOTE DATA
Line No.Column:
Line No.Column:
Se tember 30, 2006.
firm transactions.
Line No.Column:
Line No.Column: j
Line No.Column:
Line No.Column: j
Line No.Column:
Line No.Column:
Line No.Column:
firm transactions.
firm transactions.
Line No.Column:
Line No.
--.J
Column: j
Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ At) .original (Mo, Da, Yr)
PacifiCorp (2) ~Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
Settlement Ad'ustment.
Schedule Pa e: 310.Line No.: 8 Column: j
Liquidated Damages.
!schedule Page: 310.Line No.: 9 Column: b
Cowlitz County Public Utility District No.1 - FERC 234 - Contract Termination date: December 31, 2005.
ISchedule Page: 310.Line No.: 10 Column: b
Second , Econom and/or non-finn sales, including some hourly fmn transactions.
Schedule Pa e: 310.Line No.: 10 Column:
ransmission Losses.
!schedule Page: 310.Line No.: 1 Column: b
Secondary, Econom and/or non-finn sales, including some hourly finn transactions.
Schedule Page: 310.Line No.Column:
eratin Reserves.
chedule Page: 310.Line No.: 3 Column: b
Secondary, Econom and/or non-finn sales, including some hourly finn transactions.
chedule Pa e: 310.Line No.Column: j
ransmission Losses.
!Schedule Page: 310.Line No.Column: b
Flathead Electric Coo erative, Inc. - FERC T-12 - Contract Termination date: S tember 30, 2006.
chedule Pa e: 310.Line No.: 11 Column: b
Hurricane, City of - FERC T-12 - Contract Tennination date: Au t 31, 2007.
chedule Pa e: 310.Line No.13 Column: b
Idaho Power Company - FERC - T -11 (point-to-Point Transmission Service under the Open Access Transmission Tariff (S.A. 212)) -
ontract termination date: May 31 2009.
!Schedule Page: 310.Line No.13 Column: j
ransmission Losses.
!schedule Page: 310.Line No.: 14 Column: b
Secondary, Econom and/or non-finn sales, includin some hourly fmn transactions.
chedule PaBe: 310.Line No.: 14 Column:
eratin Reserves.
chedule Pa e: 310.Line No.Column: j
Transmission Losses.
!Schedule Page: 310.Line No.Column: j
eserve Share.
!Schedule Page: 310.Line No.Column: j
Transmission Losses.
Schedule Pa e: 310.Line No.: 7 Column: b
Secon , Economy and/or non-finn sales, includin some hourI firm transactions.
Schedule Pa e: 310.Line No.: 12 Column: b
Morgan Stanley Capital Group, Inc. - FERC - T -12 - Contract terminination date: December 31 , 2006.
!Schedule Page: 310.Line No.13 Column: j
ransmission Losses.
!Schedule Page: 310.Line No.: 3 Column: j
eserve Share.
!Schedule Page: 310.Line No.: 5 Column: b
condary, Economy and/or non-fmn sales, including some hourly finn transactions.~dule Page: 310.Line No.: 7 Column: b
Settlement Adjustment.
ISchedule Page: 310.Line No.: 7 Column: j
Settlement Ad' ustment.
Schedule Pa e: 310.Line No.: 8 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 03/20/2006 2005/04
FOOTNOTE DATA
Ie common control.
12 months notification.
Ie common control.
12 months notification.
Ie common control.
12 months notification.
fum transactions.
Line No.Column:
Line No.Column:
Line No.Column: b
Line No.Column:
==:J
fmu transactions.
Line No.Column: b
Line No.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 I (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
October 31 2022.
firm transactions.
firm transactions.
Line No.Column: b
Line No.Column:
Line No.Column: b
Line No.Column:
firm transactions.
Line No.Column:
Line No.Column: b
Line No.Column: j
Line No.Column: b
IFERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) 2S; An Original (Mo, Da, Yr)
PacifiCorp (2)A Resubmlssion 03/20/2006 2005/Q4
FOOTNOTE DATA
Line No.: 14 Column: j
2009.
tember 30, 2006.
Line No.: 11 Column:
rum transactions.
rum transactions.
firm transactions.
2005.
Line No.: 4 Column: b
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 03/20/2006 2005/04
FOOTNOTE DATA
Column:
Line No.Column: b
Line No.Column:
contracts under EITF Issue No. 02-04.
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PaclfiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
ELE(TRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line Account
8iiII8iiINo.
. "....,.., p""""", "'"
(a)(b) (c)
1. POWER PRODUCTION EXPENSES
A. Steam Power Generation
Operation
(500) Operation Supervision and Engineering 24,017 124 19,257 545
(501) Fuel 460 560,601 431 677 442
(502) Steam Expenses 34,694 613 32,429,428
(503) Steam from Other Sources 211,469 158 192
Less) (504) Steam Transferred-Cr.
(505) Electric Expenses 028,397 066 800
(506) Miscellaneous Steam Power Expenses 294 691 32,636,462
(507) Rents 880,309 079,460
(509) Allowances
TOTAL Operation (Enter Total of Lines 4 thru 12)545 687 204 525,305 329
Maintenance
(510) Maintenance Supervision and Engineering 374 328 708,500
(511) Maintenance of Structures 16,716,514 898,725
(512) Maintenance of Boiler Plant 150,437 84,815,260
513) Maintenance of Electric Plant 895,424 124 302
(514) Maintenance of Miscellaneous Steam Plant 9,458,599 738,019
TOTAL Maintenance (Enter Total of Lines 15 thru 19)152~595,302 150,284,806
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20)698 282 506 675,590 135
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. Hvdraulic Power Generation
Operation
(535) Operation Supervision and Engineering 4,448,802 806,096
(536) Water for Power 155 594 137,864
(537) Hydraulic Expenses 376,778 371 194
(538) Electric Expenses 20,996 379
(539) Miscellaneous Hydraulic Power Generation Expenses 237 689 213 098
(540) Rents 175 519 880
TOTAL Operation (Enter Total of Lines 44 thru 49)26,415 378 619,511
FERC FORM NO.1 (ED. 12-93)Page 320
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PaclfiCorp (1) An Original (Me, Da, Yr)End of 2005/Q4
(2) Ei A Resubmission 03/20/2006
ELECTRIC OPERATION AND MAINTENANCE E KPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
LIne Account
No.urrent ear PrevIous ear
(a)(b) (c)
C. Hvdraullc Power Generation (Continued)
Maintenance
(541) Mainentance Supervision and Engineering
(542) Maintenance of Structures 088 138 338 314
(543) Maintenance of Reservoirs, Dams, and Waterways 919 845 223 292
(544) Maintenance of Electric Plant 537 342 849 609
(545) Maintenance of Miscellaneous Hydraulic Plant 582 641 232,872
TOTAL Maintenance (Enter Total of lines 53 thru 57)127 966 644 087
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)543 344 263,598
D. Other Power Generation
ODeration
(546) Operation Supervision and Engineering 586 268 633
(547) Fuel 461 763 848,687
(548) Generation Expenses 263 205 531 091
(549) Miscellaneous Other Power Generation Expenses 473,786 514 891
(550) Rents 319,501 445 992
TOTAL Operation (Enter Total of lines 62 thru 66)104 523 349 294
Maintenance
(551) Maintenance Supervision and Engineering
(552) Maintenance of Structures 191,273 100 727
(553) Maintenance of Generating and Electric Plant 1,424 850 484.838
(554) Maintenance of Miscellaneous Other Power Generation Plant 249 513 161 782
TOTAL Maintenance (Enter Total of lines 69 thru 72)865,636 747 347
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)
E. Other Power Supply Expenses
(555) Purchased Power
(556) System Control and Load Dispatching 1,451,461 1 767 418
(557) Other Expenses 131 142 360 885
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78)722,377,491 404,781,490
TOTAL Power Production ExDenses (Total of lines 21, 41 59, 74 & 79)548 173,500 211 731 864
2. TRANSMISSION EXPENSES
Operation
(560) Operation Supervision and Engineering 457 151 086 302
(561) Load Dispatching 512 428 072 585
(562) Station Expenses 569 390 036 952
(563) Overhead Lines ExDenses 188,772 344 708
564) Underground Lines Expenses
565) Transmission of Electricity by Others 360 299 944 428
(566) Miscellaneous Transmission Expenses 191 619 40,424
(567) Rents 028 958 574 819
TOTAL Operation (Enter Total of lines 83 thru 90)99,308 617 90,100 218
Maintenance
(568) Maintenance Supervision and Engineering 686 626
(569) Maintenance of Structures 466
(570) Maintenance of Station Equipment 520,157 829,952
(571) Maintenance of Overhead Lines 587,820 170,446
(572) Maintenance of Underground Lines 599 30,593
(573) Maintenance of Miscellaneous Transmission Plant 847 821 187 444
TOTAL Maintenance (Enter Total of lines 93 thru 98)15,974,180 15,223,527
100 TOTAL Transmission Expenses (Enter Total of lines 91 and 99)115,282 797 105,323,745
101 3. DISTRIBUTION EXPENSES
102 ODeration
103 (580) Operation Supervision and Engineering 226 709 23,633,967
FERC FORM NO.1 (ED. 12-93)Page 321
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/Q4
(2) Fi A Resubmission 03/20/2006
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 urrent ear PrevIous earNo.(a)(b) (c)
104 3. DISTRIBUTION Expenses (Continued)
105 (581) Load Dispatching 786,336 7 297,006
106 (582) Station Expenses 301 836 839 640
107 (583) Overhead Line Expenses 348 654 543 306
108 (584) Underground Line Expenses 514,228 895,579
109 (585) Street lighting and Sianal System Expenses 192,851 288,258
110 (586) Meter Expenses 033,168 319,872
111 (587) Customer Installations Expenses 640 119 129
112 (588) Miscellaneous Expenses 20,626,608 22,322,195
113 (589) Rents 168,615 587 250
114 TOTAL Operation (Enter Total oflines 103 thru 113)87,216,645 88,846,202
115 Maintenance
116 (590) Maintenance Supervision and Enaineering 711 039 972,442
117 (591) Maintenance of Structures 101,838 083,885
118 (592) Maintenance of Station Equipment 416,491 299,708
119 (593) Maintenance of Overhead Lines 54,444,188 389 411
120 (594) Maintenance of Underground Lines 20,517 510 23,963,619
121 (595) Maintenance of Line Transformers 175,108 269 880
122 (596) Maintenance of Street Lighting and Signal Systems 4,454,472 228,547
123 (597) Maintenance of Meters 279 992 978 990
124 (598) Maintenance of Miscellaneous Distribution Plant 17,281,723 17,849,987
125 TOTAL Maintenance (Enter Total of lines 116 thru 124)114,382,361 120,036,469
126 TOTAL Distribution Exp (Enter Total of lines 114 and 125)201 599,006 208,882 671
127 4. CUSTOMER ACCOUNTS EXPENSES
128 Operation
129 (901) Supervision 940,111 247,491
130 (902) Meter Reading Expenses 23,835,530 316,877
131 (903) Customer Records and Collection Expenses 082,123 710 918
132 (904) Uncollectible Accounts 232 503 6,409 944
133 I (905) Miscellaneous Customer Accounts Expenses 134 759 138 185
134 TOTAL Customer Accounts Expenses (Total of lines 129 thru 133)91,225,026 86,823,415
135 5. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
136 Operation
137 (907) Supervision 932,798 931 564
138 (908) Customer Assistance Expenses 489 026 567 629
139 (909) Informational and Instructional Expenses 614,258 000 992
140 (910) Miscellaneous Customer Service and Informational Expenses 262 985 322 661
141 TOTAL Cust. Service and Information. Exp. (Total lines 137 thru 140)48,299,067 822,846
142 6. SALES EXPENSES
143 Operation
144 (911) Supervision
145 (912) Demonstrating and Selling Expenses
146 (913) Advertising Expenses
147 (916) Miscellaneous Sales Expenses
148 TOTAL Sales Expenses (Enter Total of lines 144 thru 147)
149 7. ADMINISTRATIVE AND GENERAL EXPENSES
150 Operation
151 (920) Administrative and General Salaries 137 354 536 110 959,772
152 (921) Office Supplies and Expenses 087,468 425 981
153 (Less) (922) Administrative Expenses Transferred-Credit 28,826,830 662 239
FERC FORM NO.1 (ED. 12-93)Page 322
Name of Respondent
PacifiCorp
Year/Period of Report
End of 2005/04
This ~ort Is: Date of Report(1) ~An Original (Mo, Da, Yr)
(2) A Resubmission 03/20/2006
ELECTRIC OPERATION AND MAINTENANCE PENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.Line Account Amount for Am,ountJorPrevIous Year
(c)
756,397
15,441,595
796,122
008 141
853 508
217,739,875
233,211
324 108
539,322
41,233 447
783,382
225 169,932
18,968,997
236,708,872
241 288,268
19,723,050
244,892 982
895,477 523
FERC FORM NO.1 (ED. 12-93)Page 323
Name of Respondent This Report is:Date of Report Year/Period of Report
(1) ~ An Original (Mo, Da, Yr)
PacifiCorp (2) A Resubmission 03/20/2006 2005/Q4
FOOTNOTE DATA
ISchedule Page: 320 Line No.76 Column:
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 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 (fITst
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-month 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 ofEITF No. 03-
had no impact on PacifiCorp s Net income.
Sales for Resale
Purchased Power
Other Electric Revenues
Q1-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)
720 262) 21 825 245 (18 499 621)
Q4-FY 04
CY 04
$98 740 774
(91 782 690)
958 084)
FY 2004 Total
$404 012 119
(397 659 397)
352 722)
!Schedule Page: 320 Line No.158 Column: b
The $(31 743) in pension and benefit expense for the twelve months ending December 31 , 2005 represents a reclassification of a
December 31 2004 entry in January 2005.
Pensions and benefits are charged to functional accounts, which is consistent to where labor is charged. The following table
summarizes the pension and benefit expense that was charged to the functional accounts.
Twelve Months Ended
December 312005 2004
Pension & Benefits Expense $ 133 080 717 655 438
I FERC FORM NO.1 (ED. 12-87)Page 450.
Name of Respondent This
wort
Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) Fi A Resubmission 03/20/2006
PU~CHAcRED POWER hAccount 5 5)(nclu 109 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 allnon-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)
1 3 Phases Energy Services
2 AES SeaWest, Inc.
3 Alta Energy LLC
4 American Electric Power
5 Anaheim, City
6 Aquila Merchant Services, Inc.
7 Arizona Electric Power Cooperative
8 Arizona Public Service Co.
9 Arizona Public Service Co.\.-F",
Arizona Public Service CO.I~.::i,
Arizona Public Service Co.
Avista Corp.OS.,
.,,
Avista Corp.
Avista Energy, Inc.
Total
FERC FORM NO.1 (ED. 12-90)Page 326
Name of Respondent This ooort Is: Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/04(2) 0 A Resubmission 03/20/2006
CCO~\~gg~~ lljOntinUeo)~ ,~, ,n
'(lnCfudmg power ex 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (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 Iine 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)
240,000
141 181 009,32'1 101 694
135 42.11 39,424
415,02~27,O02 24E 002 248
18E 48,12E 126
093 992
60C 40,90C 900
242 57f 018,43.:13,018,433
372,47~167 785 167 785
685 563,919 563,919
895,50,446 33E 50,446 336
'. .
52,610
57C 115,140,438
57~112 33f 121 865
15,843 940 13,142 367 13,191,207 107 354 886 508 699,262 941 259 260 674 794,88E
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 2005/Q4
(2) 0 A Resubmission 03/20/2006
PU~CHA~ED POWER ~Accouot 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)
1 Avista Energy, Inc.
2 BP Energy Company
3 Ballard Hog Farms Inc.
4 Beaver City
5 Bell Mountain Power
6 Benton County Public Utility District
7 Biomass One, loP.22.22.18.
8 Birch Creek Hydro
9 Black Hills Power, Inc.
Black Hills Power, Inc.
Black Hills Power, Inc.
Black Hills Power, Inc.
Black Hills Wyoming, Inc.
Bogus Creek
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) 0 A Resubmission 03/20/2006
CCOU
H\~gi~) (L;OntlOueC)I!nCludmg power exc ange )
AD - for out-ot-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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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 (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (t)
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 ot 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)
325 08(035 31~21,035 314
899 84E 53,445,23C lL;,
/, ". '
.... .,."O;a~53,436,636
28~283
95~954
27~63C 60,630
47~412 O7E 412 075
161 391 932 875 20,149 15E'
.. '
i'1,fj~~~~655 696
14,059 722,25,722 257
48,758t .12E 242 894
24E 70~46,705
283 53~625,15,625 397
17C 074 96(074 960
011 32,19~193
15,843,940 142,367 191 207 107 354 886 508 699,262 941,259,260 674 794 88E
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ~ort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4
(2)0 A Resubmission 03/20/2006
~C~A~ED POWER hAccou1t 555)nc u 109 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 AveragecationTariff Number Demand (MW)Monthly NCP Deman Monthly CP Demand
(a)(b)(c)(d)(e)(f)
Bonneville Power Administration liAti'P:
Bonneville Power Administration
~ ,
575.575.429.
Bonneville Power Administration
Bonneville Power Administration
Bonneville Power Administration
...
OS;
Bonneville Power Administration
Boston Power An..
:,.".
Boston Power 001 001
9 Burbank, City of
Burbank, City of
CDM Hydro
California Independent System Operator
California Independent System Operator
Calpine Energy Services, loP.
~.\....
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This 'OOort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2) n A Resubmission 03/20/2006
CCOU~\x8~~) (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 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 (t). 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 (t)
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 Exchi;lnge 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)(k)(I)(m)
196
36,501 000 36,501 000
913,994
607 370
169,909
519,78~31 ,485,60~735 427
:,y
217
273 781 054
53~20,17G 20,170
98~212 784 212 784
76~1 ,370 83~370 832
'jPt5~i8~3,1 ,063,883
303 18~723 54C 18,723 540
92C 920
843,940 142 367 191 207 107 354 886 508 699,262 941 259 260 674 794,88!
FERC FORM NO.1 (ED. 12-90)Page 327.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) An Original (Mo, Da, Yr)End of 2005/04(2) n A Resubmission 03/20/2006
~C~A~ED POWER chAccou1t 5 5)nc u 109 power ex 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:
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 yeafs.
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)
1 Calpine Energy Services, loP.
Cargill Power Markets, LLC
3 Central Oregon Irrigation District 2.40
4 Chelan County Public Utility District
5 Chelan County Public Utility District
6 Chelan County Public Utility District
7 Citigroup Energy, Inc.
B City of Buffalo
9 Clark Public Utilities
Clatskanie Peoples Utility District
Colorado River Commission of Nevada
Colorado Springs Utilities us. .
Colorado Springs Utilities
Commercial Energy Management
Total
FERC FORM NO.1 (ED. 12-90)Page 326.
Name of Respondent This ooort Is:Date of Report Year/Period of Report
PacifiCorp (1) X An Original (Mo, Da, Yr)End of 2005/Q4(2)0 A Resubmission 03/20/2006
CCOU~\~gg~! (L;ontJnueo)(iiiCfudmg 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 (t). For all other types of service, enter NA in columns (d), (e) and (t). 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.
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 O+k+l)No.Received Delivered
($)($)
of Settlement ($)
(g)
(h)(i)(I)(m)
39.101 151 101 151
224 538 713,691 713 691
13,861 252,020 142 121 394 147
113 205
321 864 . ~.ai49t:;3,497 695
48,33.007,015 262
184,20f 791 ,21~791 214
691 676 100,21E 123,892
186 74/1 983 30E 983,306
5,47C 315,10C 315 100
80C 20C 39,200
43C 430
82C 820
32C 66,911 66,911
15,843,940 13,142,367 191 207 107 354 886 508 699 262 941 259 260 674 794 881
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 2005/Q4(2) n A Resubmission 03/20/2006
~CHA~ED POWER chAccount 5 5)(nclu Ing power ex 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)
1 Conoco Inc.
2 Constellation Energy Commodities Group
3 Constellation Energy Commodities Group 100.75.75.
4 Coral Power
5 Curtiss Livestock
6 DR Johnson Lumber Company
7 Davis County Waste Management
8 Deschutes Valley Water District
9 Deseret Generation & Transmission 11J',""100.100.100.
Douglas County Public Utility District
Douglas County Public Utility District IPS"'C'
Douglas County Public Utility District
Draper Irrigation Company
Dry Creek
Total
FERC FORM NO.1 (ED. 12-90)Page 326.